Calumet Specialty Products Partners (CLMT) 10-Q 7 Aug 15 2015 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2015	Aug. 07, 2015
Document and Entity Information [Abstract]
Entity Registrant Name	Calumet Specialty Products Partners, L.P.
Entity Central Index Key	1,340,122
Document Type	10-Q
Document Period End Date	Jun. 30, 2015
Amendment Flag	false
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	Q2
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		75,760,218

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 11.7	$ 8.5
Accounts receivable:
Trade	295.8	326
Other	14.4	23.8
Total accounts receivable	310.2	349.8
Inventories	553.3	513.5
Derivative assets	1.2	23.2
Prepaid expenses and other current assets	10.4	9.2
Deferred income taxes	6.1	2.3
Total current assets	892.9	906.5
Property, plant and equipment, net	1,588.6	1,464.4
Investment in unconsolidated affiliates	170.6	137.3
Goodwill	245.8	245.8
Other intangible assets, net	235.8	257.5
Other noncurrent assets, net	99.5	108.3
Total assets	3,233.2	3,119.8
Current liabilities:
Accounts payable	434.9	419.9
Accrued interest payable	32.5	37.6
Accrued salaries, wages and benefits	29.2	21.9
Other taxes payable	19	17.9
Other current liabilities	67.5	40
Current portion of long-term debt	0.6	0.6
Derivative liabilities	18.3	5.6
Total current liabilities	602	543.5
Deferred income taxes	22.4	32.3
Pension and postretirement benefit obligations	19.2	20
Other long-term liabilities	0.9	0.9
Long-term debt, less current portion	1,717	1,712.9
Total liabilities	2,361.5	2,309.6
Partners’ capital:
Limited partners’ interest (75,760,218 units and 69,452,233 units, issued and outstanding as of June 30, 2015 and December 31, 2014, respectively)	841.1	765.9
General partner’s interest	32.9	30.6
Accumulated other comprehensive income (loss)	(2.3)	13.7
Total partners’ capital	871.7	810.2
Total liabilities and partners’ capital	$ 3,233.2	$ 3,119.8

Condensed Consolidated Balance3

Condensed Consolidated Balance Sheets (Parenthetical) - Limited Partner [Member] - shares	Jun. 30, 2015	Dec. 31, 2014
Limited partners’ interest units issued (in shares)	75,760,218	69,452,233
Limited partners’ interest units outstanding (in shares)	75,760,218	69,452,233

Unaudited Condensed Consolidate

Unaudited Condensed Consolidated Statements of Operations - USD ($) $ in Millions	3 Months Ended				6 Months Ended
	Jun. 30, 2015		Jun. 30, 2014		Jun. 30, 2015	Jun. 30, 2014
Income Statement [Abstract]
Sales	$ 1,156.2		$ 1,434.9		$ 2,174.8	$ 2,775.9
Cost of sales	(953.5)		(1,335.9)		(1,776.9)	(2,552.1)
Gross profit	202.7		99		397.9	223.8
Operating costs and expenses:
Selling	37.8		40.7		76.2	59.7
General and administrative	31.7		20.9		70.9	46.8
Transportation	42.3		41.3		84.3	81.7
Taxes other than income taxes	4		3.6		8	5.7
Other	3.2		2.8		6.1	4.9
Operating income (loss)	83.7		(10.3)		152.4	25
Other income (expense):
Interest expense	(27.4)		(28.7)		(54.4)	(54.9)
Debt extinguishment costs	(46.6)		0		(46.6)	(89.6)
Realized gain (loss) on derivative instruments	(14)		6		(5.1)	12.6
Unrealized gain (loss) on derivative instruments	5.2		23.6		(22.7)	48.2
Losses from unconsolidated affiliates	(8.2)		(1)		(12.7)	(1.2)
Other	0.7		0.2		1.5	0.1
Total other income (expense)	(90.3)		0.1		(140)	(84.8)
Net income (loss) before income taxes	(6.6)		(10.2)		12.4	(59.8)
Income tax benefit	(9.1)		(1.9)		(13.9)	(1.7)
Net income (loss)	2.5		(8.3)		26.3	(58.1)
Allocation of net income (loss):
Net income (loss)	2.5		(8.3)		26.3	(58.1)
Less:
General partner’s interest in net income (loss)	0		(0.2)		0.5	(1.2)
General partner’s incentive distribution rights	4.2		3.9		8.4	7.7
Non-vested share based payments	0		0		0	0
Net income (loss) available to limited partners	$ (1.7)		$ (12)		$ 17.4	$ (64.6)
Weighted average limited partner units outstanding:
Basic (in shares)	76,092,517		69,604,669		73,675,251	69,614,055
Diluted (in shares)	76,092,517	[1]	69,604,669	[1]	73,730,189	69,614,055	[1]
Limited partners' interest basic and diluted net income (loss) per unit (in USD per share)	$ (0.02)		$ (0.17)		$ 0.23	$ (0.93)
Cash distributions declared per limited partner unit (in USD per share)	$ 0.685		$ 0.685		$ 1.37	$ 1.37
[1]	Total diluted weighted average limited partner units outstanding excludes 0.1 million of dilutive phantom units for the three months ended June 30, 2015. Total diluted weighted average limited partner units outstanding excludes 0.2 million and 0.1 million of dilutive phantom units for the three and six months ended June 30, 2014, respectively.

Unaudited Condensed Consolidat5

Unaudited Condensed Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Statement of Comprehensive Income [Abstract]
Net income (loss)	$ 2.5	$ (8.3)	$ 26.3	$ (58.1)
Cash flow hedges:
Cash flow hedge (gain) loss reclassified to net income (loss)	(11.5)	(1.1)	(9.8)	2.8
Change in fair value of cash flow hedges	(1.1)	8.1	(6.2)	50.5
Defined benefit pension and retiree health benefit plans	0.1	0	0.3	0.2
Foreign currency translation adjustment	0	0.1	(0.3)	0.3
Total other comprehensive income (loss)	(12.5)	7.1	(16)	53.8
Comprehensive income (loss) attributable to partners’ capital	$ (10)	$ (1.2)	$ 10.3	$ (4.3)

Unaudited Condensed Consolidat6

Unaudited Condensed Consolidated Statements of Partners' Capital - 6 months ended Jun. 30, 2015 - USD ($) $ in Millions	Total	Accumulated Other Comprehensive Income [Member]	General Partner [Member]	Limited Partner [Member]
Beginning Balance at Dec. 31, 2014	$ 810.2	$ 13.7	$ 30.6	$ 765.9
Other comprehensive loss	(16)	(16)	0	0
Net income	26.3	0	8.9	17.4
Common units repurchased for phantom unit grants	(3.6)	0	0	(3.6)
Amortization of vested phantom units	1.1	0	0	1.1
Issuances of phantom units, net of taxes withheld	(1.4)	0	0	(1.4)
Proceeds from public offerings of common units, net	161.5	0	0	161.5
Contributions from Calumet GP, LLC	3.5	0	3.5	0
Distributions to partners	(109.9)	0	(10.1)	(99.8)
Ending Balance at Jun. 30, 2015	$ 871.7	$ (2.3)	$ 32.9	$ 841.1

Unaudited Condensed Consolidat7

Unaudited Condensed Consolidated Statements of Cash Flows - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
Operating activities
Net income (loss)	$ 26.3	$ (58.1)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation and amortization	71.4	65.6
Amortization of turnaround costs	12.7	11.9
Non-cash interest expense	2.9	3.5
Non-cash debt extinguishment costs	9.1	18.7
Provision for doubtful accounts	0.2	1.2
Unrealized (gain) loss on derivative instruments	22.7	(48.2)
Non-cash equity based compensation	5.5	2.9
Deferred income tax benefit	(14.1)	(1.9)
Lower of cost or market inventory adjustment	0.8	(2.9)
Losses from unconsolidated affiliates	12.7	1.2
Other non-cash activities	3.9	2.1
Changes in assets and liabilities:
Accounts receivable	39.4	(120.6)
Inventories	(40.6)	(86.7)
Prepaid expenses and other current assets	4.5	(1.8)
Derivative activity	(3.5)	3.8
Turnaround costs	(5.9)	(22.2)
Accounts payable	(7)	162.3
Accrued interest payable	(5.1)	20.9
Accrued salaries, wages and benefits	1.6	(16)
Other taxes payable	1.3	(1.2)
Other liabilities	21.7	1.9
Pension and postretirement benefit obligations	(0.5)	(0.5)
Net cash provided by (used in) operating activities	160	(64.1)
Investing activities
Additions to property, plant and equipment	(153.2)	(105.5)
Cash paid for acquisitions, net of cash acquired	0	(234)
Investment in unconsolidated affiliates	(46)	(37.5)
Proceeds from sale of property, plant and equipment	0.2	0
Net cash used in investing activities	(199)	(377)
Financing activities
Proceeds from borrowings — revolving credit facility	637.3	390
Repayments of borrowings — revolving credit facility	(685)	(330.8)
Repayments of borrowings — senior notes	(275)	(500)
Payments on capital lease obligations	(3.5)	(0.5)
Proceeds from senior notes offering	322.6	900
Debt issuance costs	(5.6)	(16)
Proceeds from public offerings of common units, net	161.5	0
Contributions from Calumet GP, LLC	3.5	0
Common units repurchased and taxes paid for phantom unit grants	(3.6)	(2.1)
Cash settlement of unit based compensation	0	(0.9)
Distributions to partners	(110)	(105.1)
Net cash provided by financing activities	42.2	334.6
Net increase (decrease) in cash and cash equivalents	3.2	(106.5)
Cash and cash equivalents at beginning of period	8.5	121.1
Cash and cash equivalents at end of period	11.7	14.6
Supplemental disclosure of non-cash financing and investing activities
Non-cash property, plant and equipment additions	$ 61.9	$ 25.4

Description of the Business

Description of the Business	6 Months Ended
	Jun. 30, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Description of the Business	Description of the Business Calumet Specialty Products Partners, L.P. (the “Company”) is a publicly traded Delaware limited partnership listed on the NASDAQ Global Select Market (“NASDAQ”) under the ticker symbol “CLMT.” The general partner of the Company is Calumet GP, LLC, a Delaware limited liability company. As of June 30, 2015 , the Company had 75,760,218 limited partner common units and 1,546,126 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 is also engaged in the resale of purchased crude oil to third party customers. The Company is based in Indianapolis, Indiana and owns specialty and fuel products facilities primarily located in northwest Louisiana, northwest Wisconsin, northern Montana, western Pennsylvania, Texas, New Jersey, eastern Missouri and North Dakota. The Company owns and leases oilfield services locations in Texas, Oklahoma, Louisiana, Arkansas, Colorado, Utah, Wyoming, Montana, New Mexico, New York, North Dakota, Pennsylvania and Ohio. 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 June 30, 2015 and for the three and six months ended June 30, 2015 and 2014 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 and six months ended June 30, 2015 are not necessarily indicative of the results that may be expected for the year ending December 31, 2015 . These unaudited condensed consolidated financial statements should be read in conjunction with the Company’s 2014 Annual Report.

Summary of Significant Accounti

Summary of Significant Accounting Policies	6 Months Ended
	Jun. 30, 2015
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Summary of Significant Accounting Policies New Accounting Pronouncements In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”), which supersedes the revenue recognition requirements in Accounting Standards Codification 605, Revenue Recognition. ASU 2014-09 is based on the principle that revenue is recognized to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts, including significant judgments and changes in judgments and assets recognized from costs incurred to obtain or fulfill a contract. ASU 2014-09 was originally effective for fiscal periods (including interim periods) beginning after December 15, 2016. In June 2015, the FASB voted to defer the effective date by one year, with early adoption permitted as of the original effective date. The final ASU reflecting these changes is expected to be issued later this year. ASU 2014-09 allows for either a full retrospective or a modified retrospective transition method. The Company is currently evaluating the impact of this standard on its condensed consolidated financial statements. In February 2015, the FASB issued ASU No. 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis (“ASU 2015-02”). ASU 2015-02 amends the analysis that a reporting entity must perform to determine whether it should consolidate certain types of legal entities. ASU 2015-02 is effective for fiscal periods (including interim periods) beginning after December 15, 2015 and early adoption is permitted. The adoption of ASU 2015-02 is not expected to have an impact on the Company’s condensed consolidated financial statements. In April 2015, the FASB issued ASU No. 2015-03, Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs (“ASU 2015-03”). ASU 2015-03 requires debt issuance costs to be recognized in the balance sheet as a direct deduction from the related debt liability rather than as an asset. ASU 2015-03 also requires the amortization of debt issuance costs to be reported as interest expense. ASU 2015-03 is effective for fiscal periods (including interim periods) beginning after December 15, 2015 and early adoption is permitted. ASU 2015-03 must be applied retrospectively, where the balance sheet of each presented individual period is adjusted to indicate the period-specific impact of using the new guidance. The Company has not yet adopted ASU 2015-03, but the impact of adopting would result in the Company reclassifying approximately $32.3 million and $34.7 million , as of June 30, 2015 and December 31, 2014, respectively, of deferred debt issuance costs from other noncurrent assets to long-term debt in the condensed consolidated balance sheets. In April 2015, the FASB issued ASU No. 2015-04, Compensation - Retirement Benefits (Topic 715): Practical Expedient for the Measurement Date of an Employer’s Defined Benefit Obligation and Plan Assets (“ASU 2015-04”). ASU 2015-04 provides guidance for the measuring of assets in defined benefit pension plans and other retirement plans if they are on fiscal years that do not end on the last day of a month. ASU 2015-04 is effective for fiscal periods (including interim periods) beginning after December 15, 2015 and early adoption is permitted. The adoption of ASU 2015-04 is not expected to have an impact on the Company’s condensed consolidated financial statements. In April 2015, the FASB issued ASU No. 2015-05, Intangibles - Goodwill and Other - Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement (“ASU 2015-05”). ASU 2015-05 provides guidance to determine whether a cloud computing agreement includes a software license or should be considered as a service agreement. ASU 2015-05 is effective for fiscal periods (including interim periods) beginning after December 15, 2015 and early adoption is permitted. An entity can elect to adopt the amendments either (1) prospectively to all arrangements entered into or materially modified after the effective date or (2) retrospectively. The Company is currently evaluating the impact of this standard on its condensed consolidated financial statements. In April 2015, the FASB issued ASU No. 2015-06, Earnings Per Share (Topic 260) - Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions (“ASU 2015-06”). ASU 2015-06 provides guidance for calculating historical earnings per unit under the two-class method, stating that the earnings or losses of a transferred business before the date of a dropdown transaction should be allocated entirely to the general partner interest. ASU 2015-06 is effective for fiscal periods (including interim periods) beginning after December 15, 2015 and early adoption is permitted. ASU 2015-06 should be applied retrospectively. The adoption of ASU 2015-06 is not expected to have an impact on the Company’s condensed consolidated financial statements. In May 2015, the FASB issued ASU 2015-07, Fair Value Measurement (Topic 820) - Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent) (“ASU 2015-07”). ASU 2015-07 provides guidance that amends the required disclosure of investments for which fair value is measured at net asset value per share (or its equivalent). The amendments remove the requirement to make certain disclosures for all investments that are eligible to be measured at fair value using the net asset value per share practical expedient. ASU 2015-07 is effective for fiscal periods (including interim periods) beginning after December 15, 2015 and early adoption is permitted. ASU 2015-07 should be applied retrospectively. The Company is currently evaluating the impact of this standard on its condensed consolidated financial statements. In May 2015, the FASB issued ASU 2015-08, Business Combinations (Topic 805) - Pushdown Accounting - Amendments to SEC Paragraphs Pursuant to Staff Bulletin No. 115 (“ASU 2015-08”). The amendments in ASU 2015-08 amend various SEC paragraphs included in the FASB’s Accounting Standards Codification to reflect the issuance of Staff Accounting Bulletin No. 115 (“SAB 115”). SAB 115 rescinds portions of the interpretive guidance included in the SEC’s Staff Accounting Bulletins series and brings existing guidance into conformity with ASU No. 2014-17, “ Business Combinations (Topic 805): Pushdown Accounting ,” which provides an acquired entity with an option to apply pushdown accounting in its separate financial statements upon occurrence of an event in which an acquirer obtains control of the acquired entity. The Company adopted the amendments in ASU 2015-08, effective May 8, 2015, as the amendments in the update are effective upon issuance. The adoption did not have an impact on the Company’s condensed consolidated financial statements. In June 2015, the FASB issued ASU 2015-10, Technical Corrections and Improvements (“ASU 2015-10”). With regard to fair value measurement disclosures, ASU 2015-10 clarified that, for nonrecurring measurements estimated at a date during the reporting period other than the end of the reporting period, an entity should clearly indicate that the fair value information presented is not as of the period’s end as well as the date or period that the measurement was taken. The Company adopted ASU 2015-10, effective June 12, 2015, as the change was effective upon issuance. The adoption did not have an impact on the Company’s condensed consolidated financial statements. In July 2015, the FASB issued ASU 2015-12, Plan Accounting: Defined Benefits Pension Plans (Topic 960), Defined Contribution Pension Plans (Topic 962) and Health and Welfare Benefit Plans (Topic 965): I. Fully Benefit-Responsive Investment Contracts; II. Plan Investment Disclosures; and III. Measurement Date Practical Expedient (“ASU 2015-12”). This three-part ASU simplifies current benefit plan accounting and requires (i) fully benefit-responsive investment contracts to be measured, presented, and disclosed only at contract value and accordingly removes the requirement to reconcile their contract value to fair value; (ii) benefit plans to disaggregate their investments measured using fair value by general type, either on the face of the financial statements or in the notes to the financial statements; (iii) the net appreciation or depreciation in investments for the period to be presented in the aggregate rather than by general type, and removes certain disclosure requirements relevant to individual investments that represent five percent or more of net assets available for benefits. Further, the amendments in this ASU eliminate the requirement to disclose the investment strategy for certain investments that are measured using Net Asset Value (“NAV”) per share using the practical expedient in the FASB ASC Topic 820. Part III of the ASU provides a practical expedient to permit employee benefit plans to measure investments and investment-related accounts as of the month-end that is closest to the plan’s fiscal year-end, when the fiscal period does not coincide with a month-end, while requiring certain additional disclosures. The amendments in Parts I and II of this standard are effective retrospectively for fiscal years beginning after December 15, 2015 and early adoption is permitted. The amendments in Part III of this standard are effective prospectively for fiscal years beginning after December 15, 2015 and early adoption is permitted. The Company is currently evaluating the impact of this standard on its condensed consolidated financial statements.

Acquisitions

Acquisitions	6 Months Ended
	Jun. 30, 2015
Business Combinations [Abstract]
Acquisitions	Acquisitions On August 1, 2014 , the Company completed the acquisition of substantially all of the assets of privately-held Specialty Oilfield Solutions, Ltd. (“SOS”) for aggregate consideration of approximately $29.6 million , net of cash acquired (“SOS Acquisition”). SOS is a full-service drilling fluids and solids control company with operations in the Eagle Ford, Marcellus and Utica shale formations. The SOS Acquisition was financed with borrowings under the Company’s revolving credit facility. The Company believes the SOS Acquisition increases its sales into the oilfield services market, expands its geographic reach and increases its asset diversity. On March 31, 2014 , the Company completed the acquisition of 100% of the membership interests of ADF Holdings, Inc., the parent company of Anchor Drilling Fluids USA, Inc. (“Anchor”), an independent provider and marketer of drilling fluids, completion fluids and production chemicals to the oil and gas exploration industry (“Anchor Acquisition”). Total consideration was approximately $223.6 million , net of cash acquired. In connection with the Anchor Acquisition, the Company is required to pay the sellers 50% of the amount of taxes paid in a post-closing tax period that are reduced (or a refund is actually received or credited) as a result of the utilization of post-closing transaction tax deductions in the 2014 taxable year (but, for the avoidance of doubt, no other taxable year), which is estimated to be $1.0 million as of June 30, 2015 . Anchor designs, manufactures and packages drilling fluid products at its locations in Texas, Oklahoma, Louisiana, Arkansas, Colorado, Utah, Wyoming, Montana, New Mexico, New York, North Dakota, Pennsylvania and Ohio. The Anchor Acquisition was financed by using a portion of the net proceeds of approximately $884.0 million from the Company’s March 2014 private placement of 6.50% senior notes due April 15, 2021 . The Company believes the Anchor Acquisition further expands its specialty products offering, increases its sales into the oilfield services market, expands its geographic reach and increases its asset diversity. On February 28, 2014 , the Company completed the acquisition of substantially all of the assets of United Petroleum, LLC (“United Petroleum”), a marketer and distributor of high performance lubricants, for aggregate consideration of approximately $10.4 million , (“United Petroleum Acquisition”). The United Petroleum Acquisition was financed with cash on hand. The Company believes the United Petroleum Acquisition increases its position in the specialty lubricants market. There have been no changes to the purchase price allocation, goodwill or intangible assets for the SOS, Anchor and United Petroleum Acquisitions since December 31, 2014. Results of Sales and Earnings The following financial information reflects sales and operating loss of the Anchor Acquisition included in the unaudited condensed consolidated statements of operations for the six months ended June 30, 2015 (in millions): Six Months Ended June 30, 2015 Sales $ 151.5 Operating loss $ (24.3 ) Unaudited Pro Forma Financial Information The following unaudited pro forma financial information reflects the unaudited condensed consolidated results of operations of the Company as if the Anchor Acquisition had taken place on January 1, 2014 (in millions, except for per unit data): Six Months Ended June 30, 2014 Sales $ 2,858.4 Net loss $ (64.3 ) Limited partners’ interest net loss per unit — basic and diluted $ (1.02 ) The Company’s historical financial information was adjusted to give effect to the pro forma events that were directly attributable to the Anchor Acquisition. This unaudited pro forma financial information has been presented for illustrative purposes only and is not necessarily indicative of results of operations that would have been achieved had the pro forma events taken place on the dates indicated, or the future consolidated results of operations of the combined company.

Inventories

Inventories	6 Months Ended
	Jun. 30, 2015
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 $50.9 million and $18.9 million lower as of June 30, 2015 and December 31, 2014 , respectively. Inventories consist of the following (in millions): June 30, 2015 December 31, 2014 Raw materials $ 100.8 $ 77.8 Work in process 80.1 75.4 Finished goods 372.4 360.3 $ 553.3 $ 513.5 Under the LIFO method, the most recently incurred costs are charged to cost of sales and inventories are valued at the earliest acquisition costs. 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 June 30, 2015 and 2014 , the Company recorded $12.4 million and $1.6 million of gains, respectively, in cost of sales in the condensed consolidated statements of operations due to the lower of cost or market valuation. During the six months ended June 30, 2015 and 2014 , the Company recorded $0.8 million of losses and $2.9 million of gains, respectively, in cost of sales in the condensed consolidated statements of operations due to the lower of cost or market valuation.

Investment in Unconsolidated Af

Investment in Unconsolidated Affiliates	6 Months Ended
	Jun. 30, 2015
Equity Method Investments and Joint Ventures [Abstract]
Investment in Unconsolidated Affiliates	Investment in Unconsolidated Affiliates 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 and cash contributions from the Company and proceeds of $75.0 million from an unsecured 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. Additionally, MDU and the Company may make cash contributions to fund working capital needs. The joint venture allocates profits on a 50% /50% basis to the Company and MDU. 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. The Company is providing refinery operations, crude oil procurement and refined product marketing expertise to the joint venture. Dakota Prairie reached mechanical completion and was commissioned in April 2015 and commenced sales of finished products in May 2015. The Company accounts for its ownership in the Dakota Prairie joint venture under the equity method of accounting. As of June 30, 2015 and December 31, 2014 , the Company had an investment of $144.6 million and $117.2 million , respectively, in Dakota Prairie, primarily related to the development and operations of the refinery. The following represents summary financial information for Dakota Prairie, presented at 100% (in millions): Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 Operating revenue $ 48.4 $ — $ 50.1 $ — Operating loss $ (14.8 ) $ (1.6 ) $ (21.8 ) $ (2.6 ) Net loss $ (15.2 ) $ (1.6 ) $ (22.3 ) $ (2.6 ) Juniper GTL LLC On June 9, 2014 , the Company entered into a joint venture agreement with Clean Fuels North America, LLC, which is owned by SGC Energia and Great Northern Project Development, to develop, build and operate a gas-to-liquids (“GTL”) plant in Lake Charles, Louisiana, which is expected to be operational by mid-2016. The joint venture is named New Source Fuels, LLC, and it owns 100% of Juniper GTL LLC (“Juniper”). The capitalization of the joint venture is expected to be funded through $100.0 million of equity contributions and $35.0 million in senior secured debt with the joint venture as the borrower. The Company intends to invest $25.0 million in total in exchange for an equity interest of approximately 23% in the joint venture. Funding of the project will occur over the course of the construction period. The joint venture is governed by a board of managers comprised of representatives from all of the members that own at least 10% of the equity in Juniper. The Company accounts for its ownership in the Juniper joint venture under the equity method of accounting. As of June 30, 2015 and December 31, 2014 , the Company had an investment of $24.6 million and $18.5 million , respectively, in Juniper, primarily related to the development of the plant.

Commitments and Contingencies

Commitments and Contingencies	6 Months Ended
	Jun. 30, 2015
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 operates crude oil and specialty hydrocarbon refining, blending and terminal operations, which are subject to stringent federal, state, regional and local laws and regulations governing worker health and safety, the discharge of materials into the environment and environmental protection. These laws and regulations impose obligations that are applicable to the Company’s operations, such as requiring the acquisition of permits to conduct regulated activities, restricting the manner in which the Company may release materials into the environment, requiring remedial activities or capital expenditures to mitigate pollution from former or current operations, requiring the application of specific health and safety criteria addressing worker protection and imposing substantial liabilities for pollution resulting from its operations. Certain of these laws impose joint and several, strict liability for costs required to remediate and restore sites where petroleum hydrocarbons, wastes or other materials have been released or disposed. In addition, new laws and regulations, new interpretations of existing laws and regulations, increased governmental enforcement or other developments could require the Company to make additional unforeseen expenditures. Many of these laws and regulations are becoming increasingly stringent, and the cost of compliance with these requirements can be expected to increase over time. For example, on January 14, 2015, the Obama Administration announced that the EPA is expected to propose in 2015, and finalize in 2016, new regulations that will set methane emission standards for new and modified oil and gas production and natural gas processing and transmission facilities as part of the Administration’s efforts to reduce methane emissions from the oil and gas sector by up to 45% from 2012 levels by 2025. In a second example, in December 2014, the EPA published a proposed rulemaking that it expects to finalize in 2015, which rulemaking proposes to revise the National Ambient Air Quality Standard for ozone to between 65 to 70 parts per billion for both the 8-hour primary and secondary standards. Voluntary remediation of subsurface contamination is in process at certain of the Company’s refinery sites. The remedial projects are being overseen by the appropriate state agencies. Based on current investigative and remedial activities, the Company believes that the groundwater contamination at these refineries can be controlled or remedied without having a material adverse effect on the Company’s financial condition. However, such costs are often unpredictable and, therefore, there can be no assurance that the future costs will not become material. San Antonio Refinery In connection with the San Antonio Acquisition, 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 Holly Frontier Corporation (“Holly”), the owner and operator of the Montana refinery prior to its acquisition by Connacher, under an asset purchase agreement between Holly and Connacher, pursuant to which Connacher acquired the Montana refinery. Under this asset purchase agreement, Holly agreed to indemnify Connacher and Montana Refining Company, Inc., subject to timely notification, certain conditions and certain monetary baskets and caps, for environmental conditions arising under Holly’s ownership and operation of the Montana refinery and existing as of the date of sale to Connacher. During 2014, Holly provided the Company a notice challenging the Company’s position that Holly is obligated to indemnify the Company’s remediation expenses for environmental conditions to the extent arising under Holly’s ownership and operation of the refinery and existing as of the date of sale to Connacher, which expenses totaled approximately $17.8 million as of June 30, 2015 , of which $14.6 million was capitalized and $3.2 million was expensed. The Company continues to believe that Holly is responsible to indemnify the Company for these remediation expenses disputed by Holly, and the parties have participated in mediation in accordance with the dispute resolution procedure set forth in the asset purchase agreement to resolve this issue. In the event the Company is unsuccessful, the Company will be responsible for those remediation expenses. The Company expects that it may incur some expenses to remediate other environmental conditions at the Montana refinery in connection with the current capacity expansion of the 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. On April 9, 2015, the MDEQ issued a Notice of Violation to the Montana refinery for alleged violation of certain air quality permit conditions and for an opacity exceedance. The MDEQ has proposed a penalty of $0.1 million . The Company is implementing internal corrective measures in response to findings alleged in the Notice of Violation or determined by the Company. 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 $1.0 million as of June 30, 2015 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 three and six months ended June 30, 2015 , the Company incurred no expenses related to installing process equipment at the Superior refinery pursuant to the EPA fuel content regulations. For three and six months ended June 30, 2014 , the Company incurred approximately $0.1 million and $0.5 million , respectively, 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 results or results of operations. The Company is contractually indemnified by Murphy Oil Corporation (“Murphy Oil”) under an asset purchase agreement between the Company and Murphy Oil for specified environmental liabilities arising from the operation of the Superior refinery including: (i) certain obligations arising out of the Superior Consent Decree (including payment of a civil penalty required under the Superior Consent Decree), (ii) certain liabilities arising in connection with Murphy Oil’s transport of certain wastes and other materials to specified offsite real properties for disposal or recycling prior to the Superior Acquisition and (iii) certain liabilities for certain third party actions, suits or proceedings alleging exposure, prior to the Superior Acquisition, of an individual to wastes or other materials at the specified on-site real property, which wastes or other materials were spilled, released, emitted or otherwise discharged by Murphy Oil. The Company believes contractual indemnity by Murphy Oil for such specified environmental liabilities is unlimited in duration and not subject to any monetary deductibles or maximums. The amount of any damages payable by Murphy Oil pursuant to the contractual indemnities under the asset purchase agreement are net of any amount recoverable under an environmental insurance policy that the Company obtained in connection with the Superior Acquisition, which named the Company and Murphy Oil as insureds and covers environmental conditions existing at the Superior refinery prior to the Superior Acquisition. Shreveport, Cotton Valley and Princeton Refineries On December 23, 2010 , the Company entered into a settlement agreement with the Louisiana Department of Environmental Quality (“LDEQ”) under LDEQ’s “Small Refinery and Single Site Refinery Initiative,” covering the Shreveport, Princeton and Cotton Valley refineries. This settlement agreement became effective on January 31, 2012 . The settlement agreement, termed the “Global Settlement,” resolved alleged violations of the federal Clean Air Act and federal Clean Water Act regulations that arose prior to December 23, 2010 . Among other things, the Company agreed to complete beneficial environmental programs and implement emissions reduction projects at the Company’s Shreveport, Cotton Valley and Princeton refineries on an agreed-upon schedule. During the three months ended June 30, 2015 and 2014 , the Company incurred approximately $1.4 million and $0.1 million , respectively, of such expenditures. During the six months ended June 30, 2015 and 2014 , the Company incurred approximately $2.4 million and $0.2 million , respectively, of such expenditures and estimates additional expenditures of approximately $7.0 million to $9.0 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 results 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 June 30, 2015 , the trust fund contained approximately $0.7 million . In addition, Weston has remediation cost containment insurance, should Weston be unable to complete the work required under the Weston Agreement. In connection with the Bel-Ray Acquisition, the Company became a party to the Weston Agreement. Weston has been addressing the environmental issues at the Bel-Ray facility over time, and the next phase will address the groundwater issues, which extend offsite. Occupational Health and Safety The Company is subject to various laws and regulations relating to occupational health and safety, including OSHA and comparable state laws. These laws and regulations strictly govern the protection of the health and safety of employees. In addition, OSHA’s hazard communication standard requires that information be maintained about hazardous materials used or produced in the Company’s operations and that this information be provided to employees, contractors, state and local government authorities and customers. The Company maintains safety and training programs as part of its ongoing efforts to ensure compliance with applicable laws and regulations. The Company conducts periodic audits of Process Safety Management (“PSM”) systems at each of its locations subject to the PSM standard. The Company’s compliance with applicable health and safety laws and regulations has required, and continues to require, substantial expenditures. Changes in occupational safety and health laws and regulations or a finding of non-compliance with current laws and regulations could result in additional capital expenditures or operating expenses, as well as civil penalties and, in the event of a serious injury or fatality, criminal charges. The Company has completed studies to assess the adequacy of its PSM practices at its Shreveport refinery with respect to certain consensus codes and standards. During the three months ended June 30, 2015 and 2014 , the Company incurred $0.2 million and $0.3 million , respectively, of PSM related capital expenditures. During the six months ended June 30, 2015 and 2014 , the Company incurred $0.3 million and $0.5 million , respectively, of related capital expenditures and expects to incur up to $1.0 million during 2015 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 under this OSHA initiative. On March 14, 2011 , OSHA issued a Citation and Notification of Penalty (the “Cotton Valley Citation”) to the Company as a result of the Cotton Valley inspection, which included a proposed penalty amount of $0.2 million . The Company has contested the Cotton Valley Citation and 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 results of operations or financial condition. Labor Matters The Company has employees covered by various collective bargaining agreements. The Company’s Karns City facility collective bargaining agreement was ratified on April 9, 2015 and will expire on January 31, 2019. The Montana refinery collective bargaining agreement was ratified on May 14, 2015 and will expire on January 31, 2019. The Missouri esters facility collective bargaining agreement was ratified on May 1, 2015 and will expire on April 30, 2016. Legal Proceedings The Company is involved in the legal proceedings described below and is subject to other claims and litigation arising in the normal course of its business. The Company has recorded accruals with respect to certain of these matters, where appropriate, that are reflected in its unaudited 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 the matters described below and other claims and litigation currently pending cannot be determined, the Company currently does not expect that these proceedings and claims, individually or in the aggregate, will have a material adverse effect on its financial position, results of operations or cash flows. The outcome of any litigation is inherently uncertain, however, and if decided adversely to the Company, or if the Company determines that settlement of particular litigation is appropriate, the Company may be subject to liability that could have a material adverse effect on its financial position, results of operations, or cash flows. Accordingly, the Company discloses matters below for which a material loss is reasonably possible. In each case, however, the Company has either determined that the range of loss is not reasonably estimable or that any reasonably estimable range of loss is not material to its unaudited condensed consolidated financial statements. On November 12, 2014, a nationwide collective action lawsuit alleging that Anchor, a wholly owned subsidiary of the Company, failed to pay drilling fluid engineers overtime in compliance with the Fair Labor Standards Act (“FLSA”) was filed titled Jonathan Wolfe v. Anchor Drilling Fluids USA, Inc. in the U.S. District Court for the Western District of Pennsylvania (“Wolfe”). The Company filed its answer to the complaint on January 9, 2015 and the Wolfe plaintiff filed an amended complaint on February 26, 2015, adding that Anchor’s failure to pay overtime to a subclass of drilling fluid engineers violated the Pennsylvania Minimum Wage Act (the “Pennsylvania Act”). For this subclass, the Wolfe plaintiff seeks certification of a class action under the Pennsylvania Act. The Wolfe plaintiff seeks to recover overtime pay, liquidated damages and attorneys’ fees and costs. The portion of the potential liability that relates to the period prior to March 31, 2014, the date on which the Company acquired Anchor, is eligible for indemnification under the securities purchase agreement that effected that transaction; however, the right to indemnification under the securities purchase agreement for the potential Wolfe liability is subject to a deductible and limitations otherwise set forth in the securities purchase agreement. On May 1, 2015, the parties engaged in mediation and agreed to a tentative settlement of this litigation. The tentative settlement must be approved by the U.S. District Court. The tentative settlement amount is not material to the unaudited condensed consolidated financial statements. On November 21, 2014, a nationwide collective action lawsuit alleging that Anchor and the Company, as well as SOS, failed to pay solids control technicians overtime in compliance with the FLSA was filed titled Timothy Niver v. Specialty Oilfield Solutions, Ltd., et al. in the U.S. District Court for the Western District of Pennsylvania (“Niver”). The Niver plaintiff filed an amended complaint on January 21, 2015, adding that defendants’ failure to pay overtime to a subclass of solids control technicians violated the Pennsylvania Act. For this subclass, the Niver plaintiff seeks certification of a class action under the Pennsylvania Act. The Niver plaintiff seeks to recover overtime pay, liquidated damages and attorneys’ fees and costs. Anchor and the Company filed their answer to the amended complaint on February 2, 2015. The Company consented to conditional certification in the case, and notice of the collective action has been issued to potential class members. The portion of the potential liability that relates to the period prior to August 1, 2014, the date on which the Company acquired the assets of SOS, was retained by, and is the responsibility of, SOS. To the extent Anchor or the Company is found liable for damages relating to the period prior to the acquisition of the assets of SOS, Anchor and the Company are eligible for indemnification under the asset purchase agreement that effected that transaction, and no deductible is applicable; however, the right to indemnification is subject to limitations otherwise set forth in the asset purchase agreement. On June 1, 2015, the parties engaged in mediation and agreed to a tentative settlement of this litigation. The tentative settlement must be approved by the U.S. District Court. The tentative settlement amount is not material to the unaudited condensed consolidated financial statements. Standby Letters of Credit The Company has agreements with various financial institutions for standby letters of credit which have been issued primarily to vendors. As of June 30, 2015 and December 31, 2014 , the Company had outstanding standby letters of credit of $99.1 million and $114.3 million , respectively, under its senior secured revolving credit facility (the “revolving credit facility”). Refer to Note 7 for additional information regarding the Company’s revolving credit facility. At June 30, 2015 and December 31, 2014 , the maximum amount of letters of credit the Company could issue under its revolving credit facility was subject to borrowing base limitations, with a maximum letter of credit sublimit equal to $600.0 million , which amount may be increased to 90% of revolver commitments in effect ( $1.0 billion at June 30, 2015 and December 31, 2014 ) with the consent of the Agent (as defined in the revolving credit facility agreement). As of June 30, 2015 and December 31, 2014 , the Company had availability to issue letters of credit of $423.2 million and $310.8 million , respectively, under its revolving credit facility.

Long-Term Debt

Long-Term Debt	6 Months Ended
	Jun. 30, 2015
Debt Disclosure [Abstract]
Long-Term Debt	Long-Term Debt Long-term debt consisted of the following (in millions): June 30, December 31, Borrowings under amended and restated senior secured revolving credit agreement with third-party lenders, interest payments quarterly, borrowings due July 2019, weighted average interest rate of 3.4% at June 30, 2015 $ 103.1 $ 150.8 Borrowings under 2020 Notes, interest at a fixed rate of 9.625%, interest payments semiannually, borrowings due August 2020, effective interest rate of 10.1% for the six months ended June 30, 2015 — 275.0 Borrowings under 2021 Notes, interest at a fixed rate of 6.50%, interest payments semiannually, borrowings due April 2021, effective interest rate of 6.7% for the six months ended June 30, 2015 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 six months ended June 30, 2015 (1) 353.0 352.5 Borrowings under 2023 Notes, interest at a fixed rate of 7.75%, interest payments semiannually, borrowings due April 2023, effective interest rate of 8.0% for the six months ended June 30, 2015 325.0 — Capital lease obligations, at various interest rates, interest and principal payments monthly through October 2034 43.4 43.6 Less unamortized discounts (6.9 ) (8.4 ) Total long-term debt 1,717.6 1,713.5 Less current portion of long-term debt 0.6 0.6 $ 1,717.0 $ 1,712.9 (1) The balance includes a fair value interest rate hedge adjustment, which increased the debt balance by $3.0 million and $2.5 million as of June 30, 2015 and December 31, 2014 , respectively (refer to Note 8 for additional information on the interest rate swap designated as a fair value hedge at December 31, 2014). Senior Notes 7.75% Senior Notes (the “2023 Notes”) On March 27, 2015 , the Company issued and sold $325.0 million in aggregate principal amount of 7.75% senior notes due April 15, 2023 in a private placement pursuant to Section 4(a)(2) of the Securities Act of 1933, as amended (the “Securities Act”), to eligible purchasers at a discounted price of 99.257 percent of par. The 2023 Notes were resold to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the U.S. pursuant to Regulation S under the Securities Act. The Company received net proceeds of approximately $317.0 million net of discount, initial purchasers’ fees and expenses, which the Company used to fund the redemption of $178.8 million in aggregate principal amount of outstanding 2020 Notes (defined below) on April 28, 2015, to repay borrowings outstanding under its revolving credit facility and for general partnership purposes, including planned capital expenditures at the Company’s facilities and working capital. Interest on the 2023 Notes is paid semiannually in arrears on April 15 and October 15 of each year, beginning on October 15, 2015. At any time prior to April 15, 2018, the Company may on any one or more occasions redeem up to 35% of the aggregate principal amount of the 2023 Notes with the net proceeds of a public or private equity offering at a redemption price of 107.75% of the principal amount, plus any accrued and unpaid interest to the date of redemption, provided that: (1) at least 65% of the aggregate principal amount of 2023 Notes issued remains outstanding immediately after the occurrence of such redemption and (2) the redemption occurs within 180 days of the date of the closing of such public or private equity offering. On and after April 15, 2018, the Company may on any one or more occasions redeem all or a part of the 2023 Notes at the redemption prices (expressed as percentages of principal amount) set forth below, plus accrued and unpaid interest to the applicable redemption date on such 2023 Notes, if redeemed during the twelve-month period beginning on April 15 of the years indicated below: Year Percentage 2018 105.813 % 2019 103.875 % 2020 101.938 % 2021 and thereafter 100.000 % Prior to April 15, 2018, the Company may on any one or more occasions redeem all or part of the 2023 Notes at a redemption price equal to the sum of: (1) the principal amount thereof, plus (2) the make-whole premium (as set forth in the indenture governing the 2023 Notes) at the redemption date, plus any accrued and unpaid interest to the applicable redemption date. In connection with the private placement of the 2023 Notes, on March 27, 2015, 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 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. The Company must use reasonable best efforts to file a shelf registration statement for the resale of the 2023 Notes. If the Company fails to satisfy these obligations on a timely basis, the annual interest borne by the 2023 Notes will be increased by up to 1.0% per annum until the exchange offer is completed or the shelf registration statement is declared effective. 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 the Anchor Acquisition (refer to Note 3 for additional information), the redemption of $500.0 million in aggregate principal amount outstanding of 9.375% senior notes due 2019 (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. On March 24, 2015, the Company filed an exchange offer registration statement for the 2021 Notes with the SEC, which was declared effective on April 3, 2015. The exchange offer was completed on April 30, 2015 , thereby fulfilling all of the requirements of the 2021 Notes registration rights agreement. 7.625% Senior Notes (the “2022 Notes”) On November 26, 2013 , the Company issued and sold $350.0 million in aggregate principal amount of 7.625% senior notes due January 15, 2022 in a private placement pursuant to Section 4(a)(2) of the Securities Act, to eligible purchasers at a discounted price of 98.494 percent of par. The Company received net proceeds of approximately $337.4 million , net of discount, initial purchasers’ fees and expenses, which the Company used for general partnership purposes, to fund previously announced organic growth projects, the purchase price of the Bel-Ray acquisition and the redemption of $100.0 million in aggregate principal amount outstanding of 9.375% senior notes due 2019. Interest on the 2022 Notes is paid semiannually in arrears on January 15 and July 15 of each year, beginning on July 15, 2014. 9.625% Senior Notes (the “2020 Notes”) On June 29, 2012 , in connection with the acquisition of Royal Purple, Inc. (“Royal Purple”), the Company issued and sold $275.0 million in aggregate principal amount of 9.625% senior notes due August 1, 2020 in a private placement pursuant to Section 4(a)(2) of the Securities Act, to eligible purchasers at a discounted price of 98.25 percent of par. The Company received net proceeds of approximately $262.5 million , net of discount, initial purchasers’ fees and expenses, which the Company used to fund a portion of the purchase price of Royal Purple. Interest on the 2020 Notes was previously paid semiannually in arrears on February 1 and August 1 of each year, beginning on February 1, 2013. On April 27, 2015 , the Company redeemed $96.2 million aggregate principal amount of 2020 Notes with a portion of the net proceeds of the March 13, 2015 public offering of its common units in which it sold 6,000,000 common units. Additionally, on April 28, 2015 , the Company redeemed the remaining $178.8 million aggregate principal amount of 2020 Notes with a portion of the net proceeds from the issuance of the 2023 Notes. In conjunction with the redemptions, the Company incurred debt extinguishment costs of $46.6 million . 2021 Notes, 2022 Notes and 2023 Notes In accordance with SEC Rule 3-10 of Regulation S-X, condensed consolidated financial statements of non-guarantors are not required. The Company has no assets or operations independent of its subsidiaries. Obligations under its 2021, 2022 and 2023 Notes are fully and unconditionally and jointly and severally guaranteed on a senior unsecured basis by the Company’s current 100%-owned operating subsidiaries and certain of the Company’s future operating subsidiaries, with the exception of the Company’s “minor” subsidiaries (as defined by Rule 3-10 of Regulation S-X), including Calumet Finance Corp. (100%-owned Delaware corporation that was organized for the sole purpose of being a co-issuer of certain of the Company’s indebtedness, including the 2021, 2022 and 2023 Notes). There are no significant restrictions on the ability of the Company or subsidiary guarantors for the Company to obtain funds from its subsidiary guarantors by dividend or loan. None of the subsidiary guarantors’ assets represent restricted assets pursuant to SEC Rule 4-08(e)(3) of Regulation S-X. The 2021, 2022 and 2023 Notes are subject to certain automatic customary releases, including the sale, disposition, or transfer of capital stock or substantially all of the assets of a subsidiary guarantor, designation of a subsidiary guarantor as unrestricted in accordance with the applicable indenture, exercise of legal defeasance option or covenant defeasance option, liquidation or dissolution of the subsidiary guarantor and a subsidiary guarantor ceases to both guarantee other Company debt and to be an obligor under the revolving credit facility. The Company’s operating subsidiaries may not sell or otherwise dispose of all or substantially all of their properties or assets to, or consolidate with or merge into, another company if such a sale would cause a default under the indentures governing the 2021, 2022 and 2023 Notes. The indentures governing the 2021, 2022 and 2023 Notes contain covenants that, among other things, restrict the Company’s ability and the ability of certain of the Company’s subsidiaries to: (i) sell assets; (ii) pay distributions on, redeem or repurchase the Company’s common units or redeem or repurchase its subordinated debt; (iii) make investments; (iv) incur or guarantee additional indebtedness or issue preferred units; (v) create or incur certain liens; (vi) enter into agreements that restrict distributions or other payments from the Company’s restricted subsidiaries to the Company; (vii) consolidate, merge or transfer all or substantially all of the Company’s assets; (viii) engage in transactions with affiliates and (ix) create unrestricted subsidiaries. These covenants are subject to important exceptions and qualifications. At any time when the 2021, 2022 and 2023 Notes are rated investment grade by either Moody’s Investors Service, Inc. (“Moody’s”) or Standard & Poor’s Ratings Services (“S&P”) and no Default or Event of Default, each as defined in the indentures governing the 2021, 2022 and 2023 Notes, has occurred and is continuing, many of these covenants will be suspended. As of June 30, 2015 , the Company’s Fixed Charge Coverage Ratio (as defined in the indentures governing the 2021, 2022 and 2023 Notes) was 3.1 to 1.0. As of June 30, 2015 , 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 prime plus a basis points margin or London Interbank Offered Rate (“LIBOR”) plus a basis points margin, at the Company’s option. As of June 30, 2015 , the margin was 75 basis points for prime and 175 basis points for LIBOR; however, the margin can fluctuate quarterly based on the Company’s average availability for additional borrowings under the revolving credit facility in the preceding calendar quarter. In addition to paying interest quarterly on outstanding borrowings under the revolving credit facility, the Company is required to pay a commitment fee to the lenders under the revolving credit facility with respect to the unutilized commitments thereunder at a rate equal to 0.250% or 0.375% per annum depending on the average daily available unused borrowing capacity for the preceding month. The Company also pays a customary letter of credit fee, including a fronting fee of 0.125% per annum of the stated amount of each outstanding letter of credit, and customary agency fees. The borrowing capacity at June 30, 2015 under the revolving credit facility was $625.3 million . As of June 30, 2015 , the Company had $103.1 million in outstanding borrowings under the revolving credit facility and outstanding standby letters of credit of $99.1 million , leaving $423.2 million available for additional borrowings based on specified availability limitations. Lenders under the revolving credit facility have a first priority lien on the Company’s accounts receivable, inventory and substantially all of its cash. The revolving credit facility contains various covenants that limit, among other things, the Company’s ability to: incur indebtedness; grant liens; dispose of certain assets; make certain acquisitions and investments; redeem or prepay other debt or make other restricted payments such as distributions to unitholders; enter into transactions with affiliates and enter into a merger, consolidation or sale of assets. Further, the revolving credit facility contains one springing financial covenant which provides that only if the Company’s availability under the revolving credit facility falls below the greater of (a) 12.5% of the Borrowing Base (as defined in the revolving credit agreement) then in effect and (b) $45.0 million, then the Company will be required to maintain as of the end of each fiscal quarter a Fixed Charge Coverage Ratio (as defined in the revolving credit agreement) of at least 1.0 to 1.0 . As of June 30, 2015 , the Company was in compliance with all covenants under the revolving credit facility. Maturities of Long-Term Debt As of June 30, 2015 , principal payments on debt obligations and future minimum rentals on capital lease obligations are as follows (in millions): Year 2015 $ 0.3 2016 0.7 2017 0.7 2018 0.8 2019 103.9 Thereafter 1,615.1 Total $ 1,721.5

Derivatives

Derivatives	6 Months Ended
	Jun. 30, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivatives	Derivatives The Company is exposed to price risks due to fluctuations in the price of crude oil, refined products (primarily in the Company’s fuel products segment), natural gas and precious metals. The Company uses various strategies to reduce its exposure to commodity price risk. The strategies to reduce the Company’s risk utilize both physical forward contracts and financially settled derivative instruments, such as swaps, collars and options, to attempt to reduce the Company’s exposure with respect to: • crude oil purchases and sales; • fuel product sales and purchases; • natural gas purchases; • precious metals purchases; and • fluctuations in the value of crude oil between geographic regions and between the different types of crude oil such as NYMEX West Texas Intermediate (“NYMEX WTI”), Light Louisiana Sweet (“LLS”), Western Canadian Select (“WCS”), Mixed Sweet Blend (“MSW”) and ICE Brent (“Brent”). The Company manages its exposure to commodity markets, credit, volumetric and liquidity risks to manage its costs and volatility of cash flows as conditions warrant or opportunities become available. These risks may be managed in a variety of ways that may include the use of derivative instruments. Derivative instruments may be used for the purpose of mitigating risks associated with an asset, liability, and anticipated future transactions 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 9 ) 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 June 30, 2015 and December 31, 2014 (in millions): June 30, 2015 December 31, 2014 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 designated as hedges: Fuel products segment: Crude oil swaps $ — $ — $ — $ — $ (10.0 ) $ (10.0 ) Gasoline swaps — — — 15.9 (4.4 ) 11.5 Swaps not allocated to a specific segment: Interest rate swaps — 2.5 — 2.5 Total derivative instruments designated as hedges — — — 18.4 (14.4 ) 4.0 Derivative instruments not designated as hedges: Fuel products segment: Crude oil swaps 1.7 (2.3 ) (0.6 ) 31.4 (111.2 ) (79.8 ) Crude oil basis swaps — — — 0.8 — 0.8 Crude oil percentage basis swaps 2.3 (2.3 ) — — (0.2 ) (0.2 ) Crude oil options 1.1 (1.1 ) — — — — Gasoline swaps — — — 2.4 (0.4 ) 2.0 Gasoline crack spread swaps 0.9 (0.9 ) — — — — Diesel swaps 1.6 (0.9 ) 0.7 116.1 (19.1 ) 97.0 Diesel crack spread swaps 5.6 (4.0 ) 1.6 4.5 — 4.5 Jet fuel swaps — — — 7.9 (5.2 ) 2.7 Platinum swaps — — — — (0.1 ) (0.1 ) Specialty products segment: Natural gas swaps — (0.5 ) (0.5 ) — (7.2 ) (7.2 ) Natural gas collars — — — 0.1 (0.6 ) (0.5 ) Total derivative instruments not designated as hedges 13.2 (12.0 ) 1.2 163.2 (144.0 ) 19.2 Total derivative instruments $ 13.2 $ (12.0 ) $ 1.2 $ 181.6 $ (158.4 ) $ 23.2 The following tables summarize the Company’s gross fair values of its derivative instruments, presenting the impact of offsetting derivative liabilities in the Company’s condensed consolidated balance sheets as of June 30, 2015 and December 31, 2014 (in millions): June 30, 2015 December 31, 2014 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 designated as hedges: Fuel products segment: Crude oil swaps $ — $ — $ — $ (13.8 ) $ 10.0 $ (3.8 ) Gasoline swaps — — — — 4.4 4.4 Total derivative instruments designated as hedges — — — (13.8 ) 14.4 0.6 Derivative instruments not designated as hedges: Fuel products segment: Crude oil swaps (2.5 ) 2.3 (0.2 ) (102.4 ) 111.2 8.8 Crude oil percentage basis swaps — 2.3 2.3 (0.2 ) 0.2 — Crude oil options (2.1 ) 1.1 (1.0 ) — — — Gasoline swaps (7.5 ) — (7.5 ) (1.0 ) 0.4 (0.6 ) Gasoline crack spread swaps (4.1 ) 0.9 (3.2 ) — — — Diesel swaps (0.1 ) 0.9 0.8 (28.1 ) 19.1 (9.0 ) Diesel crack spread swaps — 4.0 4.0 — — — Jet fuel swaps — — — (5.2 ) 5.2 — Platinum swaps (0.4 ) — (0.4 ) (0.1 ) 0.1 — Natural gas swaps (0.3 ) — (0.3 ) — — — Specialty products segment: Natural gas swaps (12.4 ) 0.5 (11.9 ) (12.1 ) 7.2 (4.9 ) Natural gas collars (0.9 ) — (0.9 ) (1.1 ) 0.6 (0.5 ) Total derivative instruments not designated as hedges (30.3 ) 12.0 (18.3 ) (150.2 ) 144.0 (6.2 ) Total derivative instruments $ (30.3 ) $ 12.0 $ (18.3 ) $ (164.0 ) $ 158.4 $ (5.6 ) The Company is exposed to credit risk in the event of nonperformance by its counterparties on these derivative transactions. The Company does not expect nonperformance on any derivative instruments, however, no assurances can be provided. The Company’s credit exposure related to these derivative instruments is represented by the fair value of contracts reported as derivative assets. As of June 30, 2015 , the Company had one counterparty in which derivatives held were net assets. As of December 31, 2014 , the Company had five 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 June 30, 2015 or December 31, 2014 . The Company’s contracts with these counterparties allow for netting of derivative instruments executed under each contract. Collateral received from counterparties is reported in other current liabilities, and collateral held by counterparties is reported in deposits, on the Company’s condensed consolidated balance sheets and is not netted against derivative assets or liabilities. As of June 30, 2015 and December 31, 2014 , 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. 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 June 30, 2015 and 2014 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 Income (Loss) on Derivatives (Effective Portion) Amount of Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (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 June 30, June 30, June 30, 2015 2014 2015 2014 2015 2014 Fuel products segment: Crude oil swaps $ (2.7 ) $ 53.5 Cost of sales $ (53.2 ) $ 13.6 Unrealized/ Realized $ — $ 30.3 Gasoline swaps 2.7 (8.2 ) Sales 19.3 (5.8 ) Unrealized/ Realized — (3.6 ) Diesel swaps (1.4 ) (33.4 ) Sales 39.8 (4.9 ) Unrealized/ Realized — (1.6 ) Jet fuel swaps 0.3 (3.8 ) Sales 4.0 (0.9 ) Unrealized/ Realized — (0.5 ) Specialty products segment: Crude oil swaps — — Cost of sales 1.6 (0.9 ) Unrealized/ Realized — — Total $ (1.1 ) $ 8.1 $ 11.5 $ 1.1 $ — $ 24.6 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 six months ended June 30, 2015 and 2014 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 Income (Loss) on Derivatives (Effective Portion) Amount of Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) into Net Income (Loss) (Effective Portion) Amount of Gain (Loss) Recognized in Net Income (Loss) on Derivatives (Ineffective Portion) Six Months Ended Location of Gain (Loss) Six Months Ended Location of Gain (Loss) Six Months Ended June 30, June 30, June 30, 2015 2014 2015 2014 2015 2014 Fuel products segment: Crude oil swaps $ (9.0 ) $ 71.2 Cost of sales $ (74.7 ) $ 23.1 Unrealized/ Realized $ (0.2 ) $ 47.7 Gasoline swaps 3.5 (10.0 ) Sales 33.3 (11.5 ) Unrealized/ Realized 0.7 (4.5 ) Diesel swaps (1.3 ) (13.4 ) Sales 44.6 (11.1 ) Unrealized/ Realized — (0.1 ) Jet fuel swaps 0.6 2.7 Sales 5.4 (2.1 ) Unrealized/ Realized — (0.4 ) Specialty products segment: Crude oil swaps — — Cost of sales 1.2 (1.2 ) Unrealized/ Realized — — Total $ (6.2 ) $ 50.5 $ 9.8 $ (2.8 ) $ 0.5 $ 42.7 The effective portion of the cash flow hedges classified in accumulated other comprehensive income (loss) was a gain of $9.7 million and a gain of $25.8 million as of June 30, 2015 and December 31, 2014 , respectively. Absent a change in the fair market value of the underlying transactions, except for any underlying transactions pertaining to the payment of interest on existing financial instruments, the following other comprehensive income (loss) at June 30, 2015 will be reclassified to earnings by December 31, 2016 with balances being recognized as follows (in millions): Year Accumulated Other Comprehensive Income (Loss) 2015 $ (1.1 ) 2016 10.8 Total $ 9.7 Based on fair values as of June 30, 2015 , the Company expects to reclassify $4.6 million of net gains on derivative instruments from accumulated other comprehensive income to earnings during the next twelve months due to actual crude oil purchases, diesel, gasoline and jet fuel sales. However, the amounts actually realized will be dependent on the fair values as of the dates of settlement. Derivative Instruments Designated as Fair Value Hedges For derivative instruments that are designated and qualify as a fair value hedge, such as an interest rate swap, 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 and six months ended June 30, 2015 and 2014 related to its derivative instrument designated as a fair value hedge (in millions): Location of Gain (Loss) of Derivative Amount of Loss Recognized in Net Income (Loss) Hedged Item Location of Gain (Loss) on Hedged Item Amount of Gain Recognized in Net Income (Loss) Three Months Ended June 30, Six Months Ended June 30, Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 2015 2014 2015 2014 Swaps not allocated to a specific segment: Interest rate swap Interest income (expense) $ — $ 1.0 $ — $ (0.6 ) 2022 Notes Interest income (expense) $ — $ (1.0 ) $ — $ 0.6 Total $ — $ 1.0 $ — $ (0.6 ) $ — $ (1.0 ) $ — $ 0.6 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, crude oil options and platinum swaps that are not designated as cash flow hedges for accounting purposes. The amount reclassified from accumulated other comprehensive income (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 and losses in the unaudited condensed consolidated statements of operations for the three and six months ended June 30, 2015 (in millions): Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 Realized gain (loss) on derivative instruments $ 1.2 $ (2.1 ) $ 2.4 $ (3.3 ) The Company recorded the following gains (losses) in its unaudited condensed consolidated statements of operations for the three months ended June 30, 2015 and 2014 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 June 30, Three Months Ended June 30, 2015 2014 2015 2014 Fuel products segment: Crude oil swaps $ 7.7 $ 10.5 $ 5.2 $ 11.1 Crude oil basis swaps — 0.6 2.2 (1.8 ) Gasoline swaps (16.4 ) (7.6 ) (7.1 ) (1.5 ) Diesel swaps 1.2 (1.6 ) (3.8 ) (5.5 ) Diesel crack spread swaps — — 7.4 — Gasoline crack spread swaps (3.9 ) — (1.7 ) — Jet fuel swaps — (0.1 ) — — Diesel crack spread collars — 0.6 — — Platinum swaps — — (0.2 ) — Natural gas swaps — — — — Gasoline crack spread collars — — — (0.5 ) Specialty products segment: Natural gas swaps (2.5 ) 0.4 3.1 0.4 Total $ (13.9 ) $ 2.8 $ 5.1 $ 2.2 The Company recorded the following gains (losses) in its unaudited condensed consolidated statements of operations for the six months ended June 30, 2015 and 2014 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 Six Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 Fuel products segment: Crude oil swaps $ (40.6 ) $ 14.4 $ 55.4 $ 14.5 Crude oil basis swaps 1.0 1.2 1.8 (0.5 ) Gasoline swaps (18.4 ) (11.2 ) (8.2 ) 1.0 Diesel swaps 59.2 (1.6 ) (67.2 ) (2.5 ) Diesel crack spread swaps 0.9 — 1.0 — Gasoline crack spread swaps (4.7 ) — (3.2 ) — Jet fuel swaps 1.6 (0.5 ) (1.6 ) (0.9 ) Diesel crack spread collars — 1.0 — 0.4 Platinum swaps — — (0.3 ) — Natural gas swaps — — (0.3 ) — Gasoline crack spread collars — — — 0.2 Specialty products segment: Natural gas swaps (4.6 ) 1.3 (0.1 ) 1.3 Total $ (5.6 ) $ 4.6 $ (22.7 ) $ 13.5 Derivative Positions - Specialty Products Segment Natural Gas Swap Contracts At June 30, 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 Third Quarter 2015 1,500,000 $ 4.11 Fourth Quarter 2015 1,900,000 $ 4.12 Calendar Year 2016 5,880,000 $ 4.22 Calendar Year 2017 4,950,000 $ 3.85 Total 14,230,000 Average price $ 4.07 At December 31, 2014 , the Company had the following derivatives related to natural gas purchases in its specialty products segment, none of which are designated as hedges. Natural Gas Swap Contracts by Expiration Dates MMBtu $/MMBtu First Quarter 2015 1,770,000 $ 4.09 Second Quarter 2015 1,500,000 $ 4.11 Third Quarter 2015 1,500,000 $ 4.11 Fourth Quarter 2015 1,900,000 $ 4.12 Calendar Year 2016 5,880,000 $ 4.22 Calendar Year 2017 1,830,000 $ 4.28 Total 14,380,000 Average price $ 4.18 Natural Gas Collars At June 30, 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) Third Quarter 2015 240,000 $ 4.25 $ 3.79 Fourth Quarter 2015 200,000 $ 4.25 $ 3.85 Calendar Year 2016 600,000 $ 4.25 $ 3.89 Total 1,040,000 Average price $ 4.25 $ 3.86 At December 31, 2014 , the Company had the following derivatives related to natural gas purchases in its specialty products segment, none of which are designated as hedges. Natural Gas Collars by Expiration Dates MMBtu Average Bought Call ($/MMBtu) Average Sold Put ($/MMBtu) First Quarter 2015 240,000 $ 4.25 $ 3.79 Second Quarter 2015 240,000 $ 4.25 $ 3.79 Third Quarter 2015 240,000 $ 4.25 $ 3.79 Fourth Quarter 2015 200,000 $ 4.25 $ 3.85 Calendar Year 2016 600,000 $ 4.25 $ 3.89 Total 1,520,000 Average price $ 4.25 $ 3.84 Derivative Positions - Fuel Products Segment Natural Gas Swap Contracts At June 30, 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 Calendar Year 2016 1,320,000 $ 3.38 Total 1,320,000 Average price $ 3.38 Crude Oil Swap Contracts At June 30, 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 Third Quarter 2015 955,000 10,380 $ 58.96 Fourth Quarter 2015 185,000 2,011 $ 61.48 Calendar Year 2016 720,288 1,968 $ 62.71 Total 1,860,288 Average price $ 60.66 At June 30, 2015 , 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 Third Quarter 2015 120,000 1,304 $ 38.75 Total 120,000 Average price $ 38.75 At December 31, 2014 , the Company had the following derivatives related to crude oil purchases in its fuel products segment, all of which are designated as cash flow hedges. Crude Oil Swap Contracts by Expiration Dates Barrels Purchased BPD Average Swap First Quarter 2015 315,000 3,500 $ 97.71 Total 315,000 Average price $ 97.71 At December 31, 2014 , the Company had the following derivatives related to crude oil purchases in its fuel products segment, none of which are designated as hedges. Crude Oil Swap Contracts by Expiration Dates Barrels Purchased BPD Average Swap First Quarter 2015 1,674,000 18,600 $ 89.55 Second Quarter 2015 91,000 1,000 $ 89.89 Third Quarter 2015 386,400 4,200 $ 69.20 Fourth Quarter 2015 386,400 4,200 $ 69.20 Calendar Year 2016 972,828 2,658 $ 78.02 Total 3,510,628 Average price $ 81.89 At December 31, 2014 , the Company had the following derivatives related to crude oil sales in its fuel products segment, none of which are designated as hedges. Crude Oil Swap Contracts by Expiration Dates Barrels Sold BPD Average Swap First Quarter 2015 1,674,000 18,600 $ 84.21 Total 1,674,000 Average price $ 84.21 Crude Oil Basis Swap Contracts The Company has entered into crude oil basis swaps to mitigate the risk of future changes in pricing differentials between Canadian heavy crude oil and NYMEX WTI crude oil, pricing differentials between LLS and NYMEX WTI and pricing differentials between MSW and NYMEX WTI. At December 31, 2014 , the Company had the following derivatives related to crude oil basis swaps in its fuel products segment, none of which are designated as hedges. Crude Oil Basis Swap Contracts by Expiration Dates Barrels Purchased BPD Average Differential to NYMEX WTI First Quarter 2015 118,000 2,000 $ (22.40 ) Total 118,000 Average differential $ (22.40 ) Crude Oil Percentage Basis Swap Contracts The Company entered into derivative instruments to secure a percentage differential on WCS crude oil to NYMEX WTI. At June 30, 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 Third Quarter 2015 184,000 2,000 73.0 % Fourth Quarter 2015 184,000 2,000 73.0 % Calendar Year 2016 732,000 2,000 75.0 % Total 1,100,000 Average percentage 74.3 % At December 31, 2014 , the Company had the following derivatives related to crude oil percentage basis swaps in its fuel products segment, none of which are designated as hedges. Crude Oil Percentage Basis Swap Contracts by Expiration Dates Barrels Purchased BPD Fixed Percentage of NYMEX WTI Third Quarter 2015 184,000 2,000 73.0 % Fourth Quarter 2015 184,000 2,000 73.0 % Total 368,000 Average percentage 73.0 % Crude Oil Option Contracts During the first quarter of 2015, the Company entered into derivative instruments to mitigate the risk of future changes in the price of NYMEX WTI crude oil. At June 30, 2015 , the Company had the following derivatives related to crude oil options bought 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) Third Quarter 2015 200,000 2,174 $ 53.50 Fourth Quarter 2015 300,000 3,261 $ 54.33 Calendar Year 2016 100,000 273 $ 55.00 Total 600,000 Average price $ 54.17 At June 30, 2015 , the Company had the following derivatives related to crude oil options sold 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) Third Quarter 2015 120,000 1,304 $ 64.71 Fourth Quarter 2015 800,000 8,696 $ 67.63 Calendar Year 2016 100,000 273 $ 65.00 Totals 1,020,000 Average price $ 67.02 Diesel Swap Contracts At June 30, 2015 , the Company had the following derivatives related to diesel sales in its fuel products segment, none of which are designated as hedges. Diesel Swap Contracts by Expiration Dates Barrels Sold BPD Average Swap ($/Bbl) Third Quarter 2015 92,000 1,000 $ 82.07 Fourth Quarter 2015 92,000 1,000 $ 82.07 Calendar Year 2016 549,000 1,500 $ 82.28 Total 733,000 Average price $ 82.22 At December 31, 2014 , the Company had the following derivatives related to diesel sales in its fuel products segment, none of which are designated as hedges. Diesel Swap Contracts by Expiration Dates Barrels Sold BPD Average Swap ($/Bbl) First Quarter 2015 1,449,000 16,100 $ 116.27 Second Quarter 2015 91,000 1,000 $ 117.92 Third Quarter 2015 322,000 3,500 $ 95.04 Fourth Quarter 2015 322,000 3,500 $ 95.04 Calendar Year 2016 915,000 2,500 $ 104.32 Total 3,099,000 Average price $ 108.38 At December 31, 2014 , the Company had the following derivatives related to diesel purchases in its fuel products segment, none of which are designated as hedges. Diesel Swap Contracts by Expiration Dates Barrels Purchased B

Fair Value Measurements

Fair Value Measurements	6 Months Ended
	Jun. 30, 2015
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Value Measurements The Company uses a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value. Observable inputs are from sources independent of the Company. Unobservable inputs reflect the Company’s assumptions about the factors market participants would use in valuing the asset or liability developed based upon the best information available in the circumstances. These tiers include the following: • Level 1—inputs include observable unadjusted quoted prices in active markets for identical assets or liabilities • Level 2—inputs include other than quoted prices in active markets that are either directly or indirectly observable • Level 3—inputs include unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions In determining fair value, the Company uses various valuation techniques and prioritizes the use of observable inputs. The availability of observable inputs varies from instrument to instrument and depends on a variety of factors including the type of instrument, whether the instrument is actively traded and other characteristics particular to the instrument. For many financial instruments, pricing inputs are readily observable in the market, the valuation methodology used is widely accepted by market participants and the valuation does not require significant management judgment. For other financial instruments, pricing inputs are less observable in the marketplace and may require management judgment. Recurring Fair Value Measurements Derivative Assets and Liabilities Derivative instruments are reported in the accompanying 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 June 30, 2015 , the Company’s net liability was reduced by approximately $0.3 million . As a result of applying the applicable CVA at June 30, 2015 , the Company’s net asset was not impacted. As a result of applying the CVA at December 31, 2014 , the Company’s net asset was increased by approximately $2.0 million and net liability was reduced by approximately $0.1 million . Observable inputs utilized to estimate the fair values of the Company’s derivative instruments were based primarily on inputs that are readily available in public markets or can be derived from information available in publicly quoted markets. Based on the use of various unobservable inputs, principally non-performance risk, creditworthiness of the hedging entities and unobservable inputs in the forward rate, the Company has categorized these derivative instruments as Level 3. Significant increases (decreases) in any of those unobservable inputs in isolation would result in a significantly lower (higher) fair value measurement. The Company believes it has obtained the most accurate information available for the types of derivative instruments it holds. See Note 8 for further information on derivative instruments. Pension Assets Pension assets are reported at fair value in the accompanying unaudited condensed consolidated financial statements. At June 30, 2015 , the Company’s investments associated with its pension plan (as such term is hereinafter defined) primarily consisted of mutual funds. The mutual funds are categorized as Level 2 because inputs used in their valuation are not quoted prices in active markets that are indirectly observable and are valued at the net asset value (“NAV”) of shares in each fund held by the pension plan at quarter end as provided by the third party administrator. See Note 11 for further information on pension assets. Liability Awards Unit based compensation liability awards are awards that are expected to be settled in cash on their vesting dates, rather than in equity units (“Liability Awards”). The Liability Awards are categorized as Level 1 because the fair value of the Liability Awards is based on the Company’s quoted closing unit price as of each balance sheet date. Renewable Identification Numbers Obligation The 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 six months ended June 30, 2015 , the Company sold approximately 49 million RINs for a gain of $35.0 million , net of cost to generate, recorded in cost of sales in the condensed consolidated statement of operations. As of June 30, 2015 , the Company had a RINs Obligation of approximately 78 million RINs, which resulted in RINs expense of approximately $32.7 million . Hierarchy of Recurring Fair Value Measurements The Company’s recurring assets and liabilities measured at fair value at June 30, 2015 and December 31, 2014 were as follows (in millions): June 30, 2015 December 31, 2014 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets: Derivative assets: Crude oil swaps $ — $ — $ (0.6 ) $ (0.6 ) $ — $ — $ (89.8 ) $ (89.8 ) Crude oil basis swaps — — — — — — 0.8 0.8 Crude oil percentage basis swaps — — — — — — (0.2 ) (0.2 ) Gasoline swaps — — — — — — 13.5 13.5 Diesel swaps — — 0.7 0.7 — — 97.0 97.0 Diesel crack spread swaps — — 1.6 1.6 — — 4.5 4.5 Jet fuel swaps — — — — — — 2.7 2.7 Natural gas swaps — — (0.5 ) (0.5 ) — — (7.2 ) (7.2 ) Natural gas collars — — — — — — (0.5 ) (0.5 ) Platinum swaps — — — — — — (0.1 ) (0.1 ) Interest rate swaps — — — — — — 2.5 2.5 Total derivative assets — — 1.2 1.2 — — 23.2 23.2 Pension plan investments 0.5 48.1 — 48.6 0.2 49.4 — 49.6 Total recurring assets at fair value $ 0.5 $ 48.1 $ 1.2 $ 49.8 $ 0.2 $ 49.4 $ 23.2 $ 72.8 Liabilities: Derivative liabilities: Crude oil swaps $ — $ — $ (0.2 ) $ (0.2 ) $ — $ — $ 5.0 $ 5.0 Crude oil percentage basis swaps — — 2.3 2.3 — — — — Gasoline swaps — — (7.5 ) (7.5 ) — — 3.8 3.8 Gasoline crack spread swaps — — (3.2 ) (3.2 ) — — — — Diesel swaps — — 0.8 0.8 — — (9.0 ) (9.0 ) Diesel crack spread swaps — — 4.0 4.0 — — — — Natural gas swaps — — (12.2 ) (12.2 ) — — (4.9 ) (4.9 ) Natural gas collars — — (0.9 ) (0.9 ) — — (0.5 ) (0.5 ) Platinum swaps — — (0.4 ) (0.4 ) — — — — Crude oil options — — (1.0 ) (1.0 ) — — — — Total derivative liabilities — — (18.3 ) (18.3 ) — — (5.6 ) (5.6 ) RINs Obligation — (41.5 ) — (41.5 ) — (16.3 ) — (16.3 ) Liability Awards (6.4 ) — — (6.4 ) (4.7 ) — — (4.7 ) Total recurring liabilities at fair value $ (6.4 ) $ (41.5 ) $ (18.3 ) $ (66.2 ) $ (4.7 ) $ (16.3 ) $ (5.6 ) $ (26.6 ) The table below sets forth a summary of net changes in fair value of the Company’s Level 3 financial assets and liabilities for the six months ended June 30, 2015 and 2014 (in millions): Six Months Ended June 30, 2015 2014 Fair value at January 1, $ 17.6 $ (54.8 ) Realized (gain) loss on derivative instruments 5.1 (12.6 ) Unrealized gain (loss) on derivative instruments (22.7 ) 48.2 Interest expense, net (0.3 ) (1.9 ) Change in fair value of cash flow hedges (6.2 ) 50.5 Settlements (10.6 ) 12.9 Transfers in (out) of Level 3 — — Fair value at June 30, $ (17.1 ) $ 42.3 Total gain (loss) included in net income (loss) attributable to changes in unrealized gain (loss) relating to financial assets and liabilities held as of June 30, $ (22.7 ) $ 48.2 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 8 for further information on derivative instruments. Nonrecurring Fair Value Measurements Certain nonfinancial assets and liabilities are measured at fair value on a nonrecurring basis and are subject to fair value adjustments in certain circumstances, such as when there is evidence of impairment. Assets and liabilities acquired in business combinations are recorded at their fair value as of the date of acquisition. The Company reviews for goodwill impairment annually on October 1 and whenever events or changes in circumstances indicate its carrying value may not be recoverable. The fair value of the reporting units is determined using the income approach. The income approach focuses on the income-producing capability of an asset, measuring the current value of the asset by calculating the present value of its future economic benefits such as cash earnings, cost savings, corporate tax structure and product offerings. Value indications are developed by discounting expected cash flows to their present value at a rate of return that incorporates the risk-free rate for the use of funds, the expected rate of inflation and risks associated with the reporting unit. These assets would generally be classified within Level 3, in the event that the Company were required to measure and record such assets at fair value within its 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 June 30, 2015 and December 31, 2014 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 7 for further information on long-term debt. The Company’s carrying and estimated fair value of the Company’s financial instruments, carried at adjusted historical cost, at June 30, 2015 and December 31, 2014 were as follows (in millions): June 30, 2015 December 31, 2014 Level Fair Value Carrying Value Fair Value Carrying Value Financial Instrument: Senior notes 1 $ 1,252.1 $ 1,248.5 $ 630.0 $ 619.1 Senior notes 2 $ 333.9 $ 322.6 $ 803.3 $ 900.0 Revolving credit facility 3 $ 103.1 $ 103.1 $ 150.8 $ 150.8 Capital lease and other obligations 3 $ 43.4 $ 43.4 $ 43.6 $ 43.6

Partners' Capital

Partners' Capital	6 Months Ended
	Jun. 30, 2015
Partners' Capital [Abstract]
Partners' Capital	Partners’ Capital On March 13, 2015 , the Company completed a public offering of its common units in which it sold 6,000,000 common units to the underwriters of the offering at a price to the public of $26.75 per unit. The proceeds received by the Company from this offering (net of underwriting discounts, commissions and expenses but before its general partner’s capital contribution) were approximately $153.9 million and were used to redeem a portion of the 2020 Notes and to repay borrowings under its revolving credit facility. Underwriting discounts totaled approximately $6.4 million . The Company’s general partner contributed $3.3 million to maintain its 2% general partner interest. 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. For the six months ended June 30, 2015 , the Company sold 307,985 common units for net proceeds of approximately $7.6 million . Underwriting discounts totaled approximately $0.1 million and the Company’s general partner contributed $0.2 million to maintain its general partner interest. The Company had no sales of its common units during the three months ended June 30, 2015 and the three and six months ended June 30, 2014 . The Company’s distribution policy is defined in its partnership agreement. For the three months ended June 30, 2015 and 2014 , the Company made distributions of $57.3 million and $52.5 million , respectively, to its partners. For the six months ended June 30, 2015 and 2014 , the Company made distributions of $110.0 million and $105.1 million , respectively, to its partners. For the three months ended June 30, 2015 and 2014 , the general partner was allocated $4.2 million and $3.9 million , respectively, in incentive distribution rights. For the six months ended June 30, 2015 and 2014 , the general partner was allocated $8.4 million and $7.7 million , respectively, in incentive distribution rights.

Employee Benefit Plans

Employee Benefit Plans	6 Months Ended
	Jun. 30, 2015
Compensation and Retirement Disclosure [Abstract]
Employee Benefit Plans	Employee Benefit Plans The components of net periodic pension cost for the three and six months ended June 30, 2015 and 2014 were as follows (in millions): Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 Service cost $ 0.2 $ 0.1 $ 0.3 $ 0.2 Interest cost 0.6 0.6 1.3 1.3 Expected return on assets (0.9 ) (0.7 ) (1.7 ) (1.5 ) Amortization of net loss 0.2 — 0.4 0.2 Net periodic benefit cost $ 0.1 $ — $ 0.3 $ 0.2 At June 30, 2015 and December 31, 2014 , the Company’s investments associated with its pension plan primarily consisted of mutual funds. The mutual funds are categorized as Level 2 because inputs used in their valuation are not quoted prices in active markets that are indirectly observable and are valued at the NAV of shares in each fund held by the pension plan at quarter end as provided by the third party administrator. See Note 9 for the definitions of Levels 1, 2 and 3. The Company’s pension plan assets measured at fair value at June 30, 2015 and December 31, 2014 were as follows (in millions): June 30, 2015 December 31, 2014 Level 1 Level 2 Level 1 Level 2 Cash and cash equivalents $ 0.5 $ — $ 0.2 $ — Domestic equities — 9.7 — 10.0 Foreign equities — 9.5 — 9.4 Fixed income — 28.9 — 30.0 $ 0.5 $ 48.1 $ 0.2 $ 49.4 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	6 Months Ended
	Jun. 30, 2015
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]
Accumulated Other Comprehensive Income	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 and six months ended June 30, 2015 and 2014 (in millions): Components of Accumulated Other Comprehensive Income (Loss) Amount Reclassified From Accumulated Other Comprehensive Income (Loss) Location of Gain (Loss) Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 Derivative gains (losses) on cash flow hedges: $ 63.1 $ (11.6 ) $ 83.3 $ (24.7 ) Sales (51.6 ) 12.7 (73.5 ) 21.9 Cost of sales $ 11.5 $ 1.1 $ 9.8 $ (2.8 ) Total Amortization of defined benefit pension and postretirement health benefit plans: Amortization of net loss $ (0.2 ) $ — $ (0.4 ) $ (0.2 ) (1) $ (0.2 ) $ — $ (0.4 ) $ (0.2 ) Total (1) This accumulated other comprehensive income (loss) component is included in the computation of net periodic pension cost. See Note 11 for additional details.

Earnings Per Unit

Earnings Per Unit	6 Months Ended
	Jun. 30, 2015
Earnings Per Unit [Abstract]
Earnings Per Unit	Earnings Per Unit The following table sets forth the computation of basic and diluted earnings per limited partner unit for the three and six months ended June 30, 2015 and 2014 (in millions, except unit and per unit data): Three Months Ended Six Months Ended June 30, June 30, 2015 2014 2015 2014 Numerator for basic and diluted earnings per limited partner unit: Net income (loss) $ 2.5 $ (8.3 ) $ 26.3 $ (58.1 ) General partner’s interest in net income (loss) — (0.2 ) 0.5 (1.2 ) General partner’s incentive distribution rights 4.2 3.9 8.4 7.7 Non-vested share based payments — — — — Net income (loss) available to limited partners $ (1.7 ) $ (12.0 ) $ 17.4 $ (64.6 ) Denominator for basic and diluted earnings per limited partner unit: Basic weighted average limited partner units outstanding 76,092,517 69,604,669 73,675,251 69,614,055 Effect of dilutive securities: Participating securities — phantom units — — 54,938 — Diluted weighted average limited partner units outstanding (1) 76,092,517 69,604,669 73,730,189 69,614,055 Limited partners’ interest basic and diluted net income (loss) per unit $ (0.02 ) $ (0.17 ) $ 0.23 $ (0.93 ) (1) Total diluted weighted average limited partner units outstanding excludes 0.1 million of dilutive phantom units for the three months ended June 30, 2015 . Total diluted weighted average limited partner units outstanding excludes 0.2 million and 0.1 million of dilutive phantom units for the three and six months ended June 30, 2014 , respectively.

Segments and Related Informatio

Segments and Related Information	6 Months Ended
	Jun. 30, 2015
Segment Reporting [Abstract]
Segments and Related Information	Segments and Related Information a. Segment Reporting The Company manages its business in multiple operating segments, which are grouped on the basis of similar product, market and operating factors into the following reportable segments: • Specialty Products. The specialty products segment produces a variety of lubricating oils, solvents, waxes, synthetic lubricants and other products which are sold to customers who purchase these products primarily as raw material components for basic automotive, industrial and consumer goods. Specialty products also include synthetic lubricants used in manufacturing, mining and automotive applications. • Fuel Products . The fuel products segment produces primarily gasoline, diesel, jet fuel and asphalt which are primarily sold to customers located in 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, production chemicals and solids control services to the oil and gas exploration 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 2014 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 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 and six months ended June 30, 2015 and 2014 is as follows (in millions): Three Months Ended June 30, 2015 Specialty Products Fuel Products Oilfield Services Combined Segments Eliminations Consolidated Total Sales: External customers $ 370.6 $ 715.1 $ 70.5 $ 1,156.2 $ — $ 1,156.2 Intersegment sales 1.7 12.1 — 13.8 (13.8 ) — Total sales $ 372.3 $ 727.2 $ 70.5 $ 1,170.0 $ (13.8 ) $ 1,156.2 Adjusted EBITDA $ 59.1 $ 50.1 $ (14.2 ) $ 95.0 $ — $ 95.0 Reconciling items to net income: Depreciation and amortization 16.7 20.2 5.7 42.6 — 42.6 Realized loss on derivatives, not reflected in net income or settled in a prior period (1.6 ) (11.0 ) — (12.6 ) — (12.6 ) Unrealized gain on derivatives (5.2 ) Interest expense 27.4 Debt extinguishment costs 46.6 Non-cash equity based compensation and other non-cash items 2.8 Income tax benefit (9.1 ) Net income $ 2.5 Three Months Ended June 30, 2014 Specialty Products Fuel Products Oilfield Services Combined Segments Eliminations Consolidated Total Sales: External customers $ 424.4 $ 900.7 $ 109.8 $ 1,434.9 $ — $ 1,434.9 Intersegment sales 7.2 27.9 — 35.1 (35.1 ) — Total sales $ 431.6 $ 928.6 $ 109.8 $ 1,470.0 $ (35.1 ) $ 1,434.9 Adjusted EBITDA $ 34.3 $ (3.1 ) $ 8.1 $ 39.3 $ — $ 39.3 Reconciling items to net loss: Depreciation and amortization 16.7 20.3 4.5 41.5 — 41.5 Realized gain on derivatives, not reflected in net loss or settled in a prior period 0.9 1.0 — 1.9 — 1.9 Unrealized gain on derivatives (23.6 ) Interest expense 28.7 Non-cash equity based compensation and other non-cash items 1.0 Income tax benefit (1.9 ) Net loss $ (8.3 ) Six Months Ended June 30, 2015 Specialty Products Fuel Products Oilfield Services Combined Segments Eliminations Consolidated Total Sales: External customers $ 732.2 $ 1,283.4 $ 159.2 $ 2,174.8 $ — $ 2,174.8 Intersegment sales 3.0 25.0 — 28.0 (28.0 ) — Total sales $ 735.2 $ 1,308.4 $ 159.2 $ 2,202.8 $ (28.0 ) $ 2,174.8 Adjusted EBITDA $ 120.7 $ 117.5 $ (18.3 ) $ 219.9 $ — $ 219.9 Reconciling items to net income: Depreciation and amortization 32.6 40.2 11.3 84.1 — 84.1 Realized loss on derivatives, not reflected in net income or settled in a prior period (1.2 ) (5.3 ) — (6.5 ) — (6.5 ) Unrealized loss on derivatives 22.7 Interest expense 54.4 Debt extinguishment costs 46.6 Non-cash equity based compensation and other non-cash items 6.2 Income tax benefit (13.9 ) Net income $ 26.3 Six Months Ended June 30, 2014 Specialty Products Fuel Products Oilfield Services Combined Segments Eliminations Consolidated Total Sales: External customers $ 874.4 $ 1,791.7 $ 109.8 $ 2,775.9 $ — $ 2,775.9 Intersegment sales 7.2 45.1 — 52.3 (52.3 ) — Total sales $ 881.6 $ 1,836.8 $ 109.8 $ 2,828.2 $ (52.3 ) $ 2,775.9 Adjusted EBITDA $ 92.0 $ 21.9 $ 8.1 $ 122.0 $ — $ 122.0 Reconciling items to net loss: Depreciation and amortization 33.4 39.6 4.5 77.5 — 77.5 Realized gain on derivatives, not reflected in net loss or settled in a prior period 1.2 2.2 — 3.4 — 3.4 Unrealized gain on derivatives (48.2 ) Interest expense 54.9 Debt extinguishment costs 89.6 Non-cash equity based compensation and other non-cash items 4.6 Income tax benefit (1.7 ) Net loss $ (58.1 ) b. Geographic Information International sales accounted for less than 10% of consolidated sales in each of the three and six months ended June 30, 2015 and 2014 . 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 June 30, 2015 and 2014 (in millions): Three Months Ended June 30, 2015 2014 Specialty products: Lubricating oils $ 158.1 13.7 % $ 184.4 12.9 % Solvents 81.6 7.1 % 120.6 8.4 % Waxes 33.9 2.9 % 30.9 2.2 % Packaged and synthetic specialty products 88.4 7.6 % 79.8 5.6 % Other 8.6 0.8 % 8.7 0.5 % Total $ 370.6 32.1 % $ 424.4 29.6 % Fuel products: Gasoline $ 302.6 26.2 % $ 358.3 25.0 % Diesel 251.0 21.7 % 268.0 18.7 % Jet fuel 37.9 3.3 % 42.1 2.9 % Asphalt, heavy fuel oils and other 123.6 10.7 % 232.3 16.2 % Total $ 715.1 61.9 % $ 900.7 62.8 % Oilfield services: Total $ 70.5 6.0 % $ 109.8 7.6 % Consolidated sales $ 1,156.2 100.0 % $ 1,434.9 100.0 % The following table sets forth the major product category sales for the six months ended June 30, 2015 and 2014 (in millions): Six Months Ended June 30, 2015 2014 Specialty products: Lubricating oils $ 307.9 14.2 % $ 382.1 13.8 % Solvents 167.8 7.7 % 252.0 9.1 % Waxes 72.9 3.4 % 66.3 2.4 % Packaged and synthetic specialty products 168.9 7.8 % 156.2 5.6 % Other 14.7 0.7 % 17.8 0.6 % Total $ 732.2 33.8 % $ 874.4 31.5 % Fuel products: Gasoline $ 548.9 25.1 % $ 717.9 25.9 % Diesel 464.9 21.4 % 585.4 21.1 % Jet fuel 76.1 3.5 % 86.1 3.1 % Asphalt, heavy fuel oils and other 193.5 8.9 % 402.3 14.4 % Total $ 1,283.4 58.9 % $ 1,791.7 64.5 % Oilfield services: Total $ 159.2 7.3 % $ 109.8 4.0 % Consolidated sales $ 2,174.8 100.0 % $ 2,775.9 100.0 % d. Major Customers During the three and six months ended June 30, 2015 and 2014 , the Company had no customer that represented 10% or greater of consolidated sales. e. Major Suppliers During the three months ended June 30, 2015 and 2014 , the Company had two suppliers that supplied approximately 49.5% and 44.0% , respectively, of its crude oil supply. During the six months ended June 30, 2015 and 2014 , the Company had two suppliers that supplied approximately 48.8% and 46.0% , respectively, of its crude oil supply.

Subsequent Events

Subsequent Events	6 Months Ended
	Jun. 30, 2015
Subsequent Events [Abstract]
Subsequent Events	Subsequent Events Subsequent events not disclosed elsewhere include the following: On July 21, 2015 , the Company declared a quarterly cash distribution of $0.685 per unit on all outstanding common units, or approximately $57.3 million (including the general partner’s incentive distribution rights) in aggregate, for the quarter ended June 30, 2015 . The distribution will be paid on August 14, 2015 to unitholders of record as of the close of business on August 4, 2015 . This quarterly distribution of $0.685 per unit equates to $2.74 per unit, or approximately $229.2 million (including the general partner’s incentive distribution rights) in aggregate on an annualized basis. The fair value of the Company’s derivatives that were outstanding as of June 30, 2015 decreased by approximately $3.0 million subsequent to June 30, 2015 to a net liability of approximately $15.0 million . The fair value of the Company’s senior notes that were outstanding as of June 30, 2015 has increased by approximately $4.0 million subsequent to June 30, 2015 .

Summary of Significant Accoun23

Summary of Significant Accounting Policies (Policies)	6 Months Ended
	Jun. 30, 2015
Accounting Policies [Abstract]
Basis of Accounting	The unaudited condensed consolidated financial statements of the Company as of June 30, 2015 and for the three and six months ended June 30, 2015 and 2014 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 and six months ended June 30, 2015 are not necessarily indicative of the results that may be expected for the year ending December 31, 2015 . These unaudited condensed consolidated financial statements should be read in conjunction with the Company’s 2014 Annual Report.
New Accounting Pronouncements	New Accounting Pronouncements In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”), which supersedes the revenue recognition requirements in Accounting Standards Codification 605, Revenue Recognition. ASU 2014-09 is based on the principle that revenue is recognized to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts, including significant judgments and changes in judgments and assets recognized from costs incurred to obtain or fulfill a contract. ASU 2014-09 was originally effective for fiscal periods (including interim periods) beginning after December 15, 2016. In June 2015, the FASB voted to defer the effective date by one year, with early adoption permitted as of the original effective date. The final ASU reflecting these changes is expected to be issued later this year. ASU 2014-09 allows for either a full retrospective or a modified retrospective transition method. The Company is currently evaluating the impact of this standard on its condensed consolidated financial statements. In February 2015, the FASB issued ASU No. 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis (“ASU 2015-02”). ASU 2015-02 amends the analysis that a reporting entity must perform to determine whether it should consolidate certain types of legal entities. ASU 2015-02 is effective for fiscal periods (including interim periods) beginning after December 15, 2015 and early adoption is permitted. The adoption of ASU 2015-02 is not expected to have an impact on the Company’s condensed consolidated financial statements. In April 2015, the FASB issued ASU No. 2015-03, Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs (“ASU 2015-03”). ASU 2015-03 requires debt issuance costs to be recognized in the balance sheet as a direct deduction from the related debt liability rather than as an asset. ASU 2015-03 also requires the amortization of debt issuance costs to be reported as interest expense. ASU 2015-03 is effective for fiscal periods (including interim periods) beginning after December 15, 2015 and early adoption is permitted. ASU 2015-03 must be applied retrospectively, where the balance sheet of each presented individual period is adjusted to indicate the period-specific impact of using the new guidance. The Company has not yet adopted ASU 2015-03, but the impact of adopting would result in the Company reclassifying approximately $32.3 million and $34.7 million , as of June 30, 2015 and December 31, 2014, respectively, of deferred debt issuance costs from other noncurrent assets to long-term debt in the condensed consolidated balance sheets. In April 2015, the FASB issued ASU No. 2015-04, Compensation - Retirement Benefits (Topic 715): Practical Expedient for the Measurement Date of an Employer’s Defined Benefit Obligation and Plan Assets (“ASU 2015-04”). ASU 2015-04 provides guidance for the measuring of assets in defined benefit pension plans and other retirement plans if they are on fiscal years that do not end on the last day of a month. ASU 2015-04 is effective for fiscal periods (including interim periods) beginning after December 15, 2015 and early adoption is permitted. The adoption of ASU 2015-04 is not expected to have an impact on the Company’s condensed consolidated financial statements. In April 2015, the FASB issued ASU No. 2015-05, Intangibles - Goodwill and Other - Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement (“ASU 2015-05”). ASU 2015-05 provides guidance to determine whether a cloud computing agreement includes a software license or should be considered as a service agreement. ASU 2015-05 is effective for fiscal periods (including interim periods) beginning after December 15, 2015 and early adoption is permitted. An entity can elect to adopt the amendments either (1) prospectively to all arrangements entered into or materially modified after the effective date or (2) retrospectively. The Company is currently evaluating the impact of this standard on its condensed consolidated financial statements. In April 2015, the FASB issued ASU No. 2015-06, Earnings Per Share (Topic 260) - Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions (“ASU 2015-06”). ASU 2015-06 provides guidance for calculating historical earnings per unit under the two-class method, stating that the earnings or losses of a transferred business before the date of a dropdown transaction should be allocated entirely to the general partner interest. ASU 2015-06 is effective for fiscal periods (including interim periods) beginning after December 15, 2015 and early adoption is permitted. ASU 2015-06 should be applied retrospectively. The adoption of ASU 2015-06 is not expected to have an impact on the Company’s condensed consolidated financial statements. In May 2015, the FASB issued ASU 2015-07, Fair Value Measurement (Topic 820) - Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent) (“ASU 2015-07”). ASU 2015-07 provides guidance that amends the required disclosure of investments for which fair value is measured at net asset value per share (or its equivalent). The amendments remove the requirement to make certain disclosures for all investments that are eligible to be measured at fair value using the net asset value per share practical expedient. ASU 2015-07 is effective for fiscal periods (including interim periods) beginning after December 15, 2015 and early adoption is permitted. ASU 2015-07 should be applied retrospectively. The Company is currently evaluating the impact of this standard on its condensed consolidated financial statements. In May 2015, the FASB issued ASU 2015-08, Business Combinations (Topic 805) - Pushdown Accounting - Amendments to SEC Paragraphs Pursuant to Staff Bulletin No. 115 (“ASU 2015-08”). The amendments in ASU 2015-08 amend various SEC paragraphs included in the FASB’s Accounting Standards Codification to reflect the issuance of Staff Accounting Bulletin No. 115 (“SAB 115”). SAB 115 rescinds portions of the interpretive guidance included in the SEC’s Staff Accounting Bulletins series and brings existing guidance into conformity with ASU No. 2014-17, “ Business Combinations (Topic 805): Pushdown Accounting ,” which provides an acquired entity with an option to apply pushdown accounting in its separate financial statements upon occurrence of an event in which an acquirer obtains control of the acquired entity. The Company adopted the amendments in ASU 2015-08, effective May 8, 2015, as the amendments in the update are effective upon issuance. The adoption did not have an impact on the Company’s condensed consolidated financial statements. In June 2015, the FASB issued ASU 2015-10, Technical Corrections and Improvements (“ASU 2015-10”). With regard to fair value measurement disclosures, ASU 2015-10 clarified that, for nonrecurring measurements estimated at a date during the reporting period other than the end of the reporting period, an entity should clearly indicate that the fair value information presented is not as of the period’s end as well as the date or period that the measurement was taken. The Company adopted ASU 2015-10, effective June 12, 2015, as the change was effective upon issuance. The adoption did not have an impact on the Company’s condensed consolidated financial statements. In July 2015, the FASB issued ASU 2015-12, Plan Accounting: Defined Benefits Pension Plans (Topic 960), Defined Contribution Pension Plans (Topic 962) and Health and Welfare Benefit Plans (Topic 965): I. Fully Benefit-Responsive Investment Contracts; II. Plan Investment Disclosures; and III. Measurement Date Practical Expedient (“ASU 2015-12”). This three-part ASU simplifies current benefit plan accounting and requires (i) fully benefit-responsive investment contracts to be measured, presented, and disclosed only at contract value and accordingly removes the requirement to reconcile their contract value to fair value; (ii) benefit plans to disaggregate their investments measured using fair value by general type, either on the face of the financial statements or in the notes to the financial statements; (iii) the net appreciation or depreciation in investments for the period to be presented in the aggregate rather than by general type, and removes certain disclosure requirements relevant to individual investments that represent five percent or more of net assets available for benefits. Further, the amendments in this ASU eliminate the requirement to disclose the investment strategy for certain investments that are measured using Net Asset Value (“NAV”) per share using the practical expedient in the FASB ASC Topic 820. Part III of the ASU provides a practical expedient to permit employee benefit plans to measure investments and investment-related accounts as of the month-end that is closest to the plan’s fiscal year-end, when the fiscal period does not coincide with a month-end, while requiring certain additional disclosures. The amendments in Parts I and II of this standard are effective retrospectively for fiscal years beginning after December 15, 2015 and early adoption is permitted. The amendments in Part III of this standard are effective prospectively for fiscal years beginning after December 15, 2015 and early adoption is permitted. The Company is currently evaluating the impact of this standard on its condensed consolidated financial statements.
Inventories	The cost of inventory is recorded using the last-in, first-out (“LIFO”) method. An actual valuation of inventory under the LIFO method can be made only at the end of each year based on the inventory levels and costs at that time. Accordingly, interim LIFO calculations are based on management’s estimates of expected year-end inventory levels and costs and are subject to the final year-end LIFO inventory valuation. Costs include crude oil and other feedstocks, labor, processing costs and refining overhead costs. Inventories are valued at the lower of cost or market value. Under the LIFO method, the most recently incurred costs are charged to cost of sales and inventories are valued at the earliest acquisition costs. In addition, the use of the LIFO inventory method may result in increases or decreases to cost of sales in years that inventory volumes decline as the result of charging cost of sales with LIFO inventory costs generated in prior periods. In periods of rapidly declining prices, LIFO inventories may have to be written down to market value due to the higher costs assigned to LIFO layers in prior periods. Such write downs are subject to reversal in subsequent periods, not to exceed LIFO cost, if prices recover. During the three months ended June 30, 2015 and 2014 , the Company recorded $12.4 million and $1.6 million of gains, respectively, in cost of sales in the condensed consolidated statements of operations due to the lower of cost or market valuation. During the six months ended June 30, 2015 and 2014 , the Company recorded $0.8 million of losses and $2.9 million of gains, respectively, in cost of sales in the condensed consolidated statements of operations due to the lower of cost or market valuation.
Derivatives	Derivative Instruments Not Designated as Hedges For derivative instruments not designated as hedges, the change in fair value of the asset or liability for the period is recorded to 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, crude oil options and platinum swaps that are not designated as cash flow hedges for accounting purposes. The Company is exposed to price risks due to fluctuations in the price of crude oil, refined products (primarily in the Company’s fuel products segment), natural gas and precious metals. The Company uses various strategies to reduce its exposure to commodity price risk. The strategies to reduce the Company’s risk utilize both physical forward contracts and financially settled derivative instruments, such as swaps, collars and options, to attempt to reduce the Company’s exposure with respect to: • crude oil purchases and sales; • fuel product sales and purchases; • natural gas purchases; • precious metals purchases; and • fluctuations in the value of crude oil between geographic regions and between the different types of crude oil such as NYMEX West Texas Intermediate (“NYMEX WTI”), Light Louisiana Sweet (“LLS”), Western Canadian Select (“WCS”), Mixed Sweet Blend (“MSW”) and ICE Brent (“Brent”). The Company manages its exposure to commodity markets, credit, volumetric and liquidity risks to manage its costs and volatility of cash flows as conditions warrant or opportunities become available. These risks may be managed in a variety of ways that may include the use of derivative instruments. Derivative instruments may be used for the purpose of mitigating risks associated with an asset, liability, and anticipated future transactions 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 9 ) 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 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. 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 Fair Value Hedges For derivative instruments that are designated and qualify as a fair value hedge, such as an interest rate swap, 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.
Fair Value Measurement	Pension Assets Pension assets are reported at fair value in the accompanying unaudited condensed consolidated financial statements. At June 30, 2015 , the Company’s investments associated with its pension plan (as such term is hereinafter defined) primarily consisted of mutual funds. The mutual funds are categorized as Level 2 because inputs used in their valuation are not quoted prices in active markets that are indirectly observable and are valued at the net asset value (“NAV”) of shares in each fund held by the pension plan at quarter end as provided by the third party administrator. See Note 11 for further information on pension assets. Liability Awards Unit based compensation liability awards are awards that are expected to be settled in cash on their vesting dates, rather than in equity units (“Liability Awards”). The Liability Awards are categorized as Level 1 because the fair value of the Liability Awards is based on the Company’s quoted closing unit price as of each balance sheet date. Renewable Identification Numbers Obligation The 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. 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. 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. 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. 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. Observable inputs utilized to estimate the fair values of the Company’s derivative instruments were based primarily on inputs that are readily available in public markets or can be derived from information available in publicly quoted markets. Based on the use of various unobservable inputs, principally non-performance risk, creditworthiness of the hedging entities and unobservable inputs in the forward rate, the Company has categorized these derivative instruments as Level 3. Significant increases (decreases) in any of those unobservable inputs in isolation would result in a significantly lower (higher) fair value measurement. The Company believes it has obtained the most accurate information available for the types of derivative instruments it holds. The Company uses a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value. Observable inputs are from sources independent of the Company. Unobservable inputs reflect the Company’s assumptions about the factors market participants would use in valuing the asset or liability developed based upon the best information available in the circumstances. These tiers include the following: • Level 1—inputs include observable unadjusted quoted prices in active markets for identical assets or liabilities • Level 2—inputs include other than quoted prices in active markets that are either directly or indirectly observable • Level 3—inputs include unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions In determining fair value, the Company uses various valuation techniques and prioritizes the use of observable inputs. The availability of observable inputs varies from instrument to instrument and depends on a variety of factors including the type of instrument, whether the instrument is actively traded and other characteristics particular to the instrument. For many financial instruments, pricing inputs are readily observable in the market, the valuation methodology used is widely accepted by market participants and the valuation does not require significant management judgment. For other financial instruments, pricing inputs are less observable in the marketplace and may require management judgment. Debt The estimated fair value of long-term debt at June 30, 2015 and December 31, 2014 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.
Segment Reporting	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. 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

Acquisitions (Tables)

Acquisitions (Tables)	6 Months Ended
	Jun. 30, 2015
Business Combinations [Abstract]
Summary of Sales and Operating Income and Unaudited Pro Forma Financial Information	Results of Sales and Earnings The following financial information reflects sales and operating loss of the Anchor Acquisition included in the unaudited condensed consolidated statements of operations for the six months ended June 30, 2015 (in millions): Six Months Ended June 30, 2015 Sales $ 151.5 Operating loss $ (24.3 ) Unaudited Pro Forma Financial Information The following unaudited pro forma financial information reflects the unaudited condensed consolidated results of operations of the Company as if the Anchor Acquisition had taken place on January 1, 2014 (in millions, except for per unit data): Six Months Ended June 30, 2014 Sales $ 2,858.4 Net loss $ (64.3 ) Limited partners’ interest net loss per unit — basic and diluted $ (1.02 )

Inventories (Tables)

Inventories (Tables)	6 Months Ended
	Jun. 30, 2015
Inventory Disclosure [Abstract]
Summary of Inventories	Inventories consist of the following (in millions): June 30, 2015 December 31, 2014 Raw materials $ 100.8 $ 77.8 Work in process 80.1 75.4 Finished goods 372.4 360.3 $ 553.3 $ 513.5

Investment in Unconsolidated 26

Investment in Unconsolidated Affiliates Equity Method Investments and Joint Ventures (Tables)	6 Months Ended
	Jun. 30, 2015
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 June 30, Six Months Ended June 30, 2015 2014 2015 2014 Operating revenue $ 48.4 $ — $ 50.1 $ — Operating loss $ (14.8 ) $ (1.6 ) $ (21.8 ) $ (2.6 ) Net loss $ (15.2 ) $ (1.6 ) $ (22.3 ) $ (2.6 )

Long-Term Debt (Tables)

Long-Term Debt (Tables)	6 Months Ended
	Jun. 30, 2015
Debt Instrument [Line Items]
Summary of Long-Term Debt	Long-term debt consisted of the following (in millions): June 30, December 31, Borrowings under amended and restated senior secured revolving credit agreement with third-party lenders, interest payments quarterly, borrowings due July 2019, weighted average interest rate of 3.4% at June 30, 2015 $ 103.1 $ 150.8 Borrowings under 2020 Notes, interest at a fixed rate of 9.625%, interest payments semiannually, borrowings due August 2020, effective interest rate of 10.1% for the six months ended June 30, 2015 — 275.0 Borrowings under 2021 Notes, interest at a fixed rate of 6.50%, interest payments semiannually, borrowings due April 2021, effective interest rate of 6.7% for the six months ended June 30, 2015 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 six months ended June 30, 2015 (1) 353.0 352.5 Borrowings under 2023 Notes, interest at a fixed rate of 7.75%, interest payments semiannually, borrowings due April 2023, effective interest rate of 8.0% for the six months ended June 30, 2015 325.0 — Capital lease obligations, at various interest rates, interest and principal payments monthly through October 2034 43.4 43.6 Less unamortized discounts (6.9 ) (8.4 ) Total long-term debt 1,717.6 1,713.5 Less current portion of long-term debt 0.6 0.6 $ 1,717.0 $ 1,712.9 (1) The balance includes a fair value interest rate hedge adjustment, which increased the debt balance by $3.0 million and $2.5 million as of June 30, 2015 and December 31, 2014 , respectively (refer to Note 8 for additional information on the interest rate swap designated as a fair value hedge at December 31, 2014).
Summary of Principal Payments on Debt Obligations and Future Minimum Rentals on Capital Lease Obligations	As of June 30, 2015 , principal payments on debt obligations and future minimum rentals on capital lease obligations are as follows (in millions): Year 2015 $ 0.3 2016 0.7 2017 0.7 2018 0.8 2019 103.9 Thereafter 1,615.1 Total $ 1,721.5
Notes Due April 2023 at Fixed Rate of 7.75% Interest Payments [Member]
Debt Instrument [Line Items]
Summary of Redemption Prices	On and after April 15, 2018, the Company may on any one or more occasions redeem all or a part of the 2023 Notes at the redemption prices (expressed as percentages of principal amount) set forth below, plus accrued and unpaid interest to the applicable redemption date on such 2023 Notes, if redeemed during the twelve-month period beginning on April 15 of the years indicated below: Year Percentage 2018 105.813 % 2019 103.875 % 2020 101.938 % 2021 and thereafter 100.000 %

Derivatives (Tables)

Derivatives (Tables)	6 Months Ended
	Jun. 30, 2015
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 June 30, 2015 and December 31, 2014 (in millions): June 30, 2015 December 31, 2014 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 designated as hedges: Fuel products segment: Crude oil swaps $ — $ — $ — $ — $ (10.0 ) $ (10.0 ) Gasoline swaps — — — 15.9 (4.4 ) 11.5 Swaps not allocated to a specific segment: Interest rate swaps — 2.5 — 2.5 Total derivative instruments designated as hedges — — — 18.4 (14.4 ) 4.0 Derivative instruments not designated as hedges: Fuel products segment: Crude oil swaps 1.7 (2.3 ) (0.6 ) 31.4 (111.2 ) (79.8 ) Crude oil basis swaps — — — 0.8 — 0.8 Crude oil percentage basis swaps 2.3 (2.3 ) — — (0.2 ) (0.2 ) Crude oil options 1.1 (1.1 ) — — — — Gasoline swaps — — — 2.4 (0.4 ) 2.0 Gasoline crack spread swaps 0.9 (0.9 ) — — — — Diesel swaps 1.6 (0.9 ) 0.7 116.1 (19.1 ) 97.0 Diesel crack spread swaps 5.6 (4.0 ) 1.6 4.5 — 4.5 Jet fuel swaps — — — 7.9 (5.2 ) 2.7 Platinum swaps — — — — (0.1 ) (0.1 ) Specialty products segment: Natural gas swaps — (0.5 ) (0.5 ) — (7.2 ) (7.2 ) Natural gas collars — — — 0.1 (0.6 ) (0.5 ) Total derivative instruments not designated as hedges 13.2 (12.0 ) 1.2 163.2 (144.0 ) 19.2 Total derivative instruments $ 13.2 $ (12.0 ) $ 1.2 $ 181.6 $ (158.4 ) $ 23.2
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 June 30, 2015 and December 31, 2014 (in millions): June 30, 2015 December 31, 2014 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 designated as hedges: Fuel products segment: Crude oil swaps $ — $ — $ — $ (13.8 ) $ 10.0 $ (3.8 ) Gasoline swaps — — — — 4.4 4.4 Total derivative instruments designated as hedges — — — (13.8 ) 14.4 0.6 Derivative instruments not designated as hedges: Fuel products segment: Crude oil swaps (2.5 ) 2.3 (0.2 ) (102.4 ) 111.2 8.8 Crude oil percentage basis swaps — 2.3 2.3 (0.2 ) 0.2 — Crude oil options (2.1 ) 1.1 (1.0 ) — — — Gasoline swaps (7.5 ) — (7.5 ) (1.0 ) 0.4 (0.6 ) Gasoline crack spread swaps (4.1 ) 0.9 (3.2 ) — — — Diesel swaps (0.1 ) 0.9 0.8 (28.1 ) 19.1 (9.0 ) Diesel crack spread swaps — 4.0 4.0 — — — Jet fuel swaps — — — (5.2 ) 5.2 — Platinum swaps (0.4 ) — (0.4 ) (0.1 ) 0.1 — Natural gas swaps (0.3 ) — (0.3 ) — — — Specialty products segment: Natural gas swaps (12.4 ) 0.5 (11.9 ) (12.1 ) 7.2 (4.9 ) Natural gas collars (0.9 ) — (0.9 ) (1.1 ) 0.6 (0.5 ) Total derivative instruments not designated as hedges (30.3 ) 12.0 (18.3 ) (150.2 ) 144.0 (6.2 ) Total derivative instruments $ (30.3 ) $ 12.0 $ (18.3 ) $ (164.0 ) $ 158.4 $ (5.6 )
Schedule of Derivative Instruments	The amount reclassified from accumulated other comprehensive income (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 and losses in the unaudited condensed consolidated statements of operations for the three and six months ended June 30, 2015 (in millions): Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 Realized gain (loss) on derivative instruments $ 1.2 $ (2.1 ) $ 2.4 $ (3.3 )
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 income (loss) was a gain of $9.7 million and a gain of $25.8 million as of June 30, 2015 and December 31, 2014 , respectively. Absent a change in the fair market value of the underlying transactions, except for any underlying transactions pertaining to the payment of interest on existing financial instruments, the following other comprehensive income (loss) at June 30, 2015 will be reclassified to earnings by December 31, 2016 with balances being recognized as follows (in millions): Year Accumulated Other Comprehensive Income (Loss) 2015 $ (1.1 ) 2016 10.8 Total $ 9.7
Specialty Product [Member] | Natural Gas Swap Contracts [Member]
Derivative [Line Items]
Schedule of Derivative Positions	Natural Gas Swap Contracts At June 30, 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 Third Quarter 2015 1,500,000 $ 4.11 Fourth Quarter 2015 1,900,000 $ 4.12 Calendar Year 2016 5,880,000 $ 4.22 Calendar Year 2017 4,950,000 $ 3.85 Total 14,230,000 Average price $ 4.07 At December 31, 2014 , the Company had the following derivatives related to natural gas purchases in its specialty products segment, none of which are designated as hedges. Natural Gas Swap Contracts by Expiration Dates MMBtu $/MMBtu First Quarter 2015 1,770,000 $ 4.09 Second Quarter 2015 1,500,000 $ 4.11 Third Quarter 2015 1,500,000 $ 4.11 Fourth Quarter 2015 1,900,000 $ 4.12 Calendar Year 2016 5,880,000 $ 4.22 Calendar Year 2017 1,830,000 $ 4.28 Total 14,380,000 Average price $ 4.18
Specialty Product [Member] | Natural Gas Collars [Member]
Derivative [Line Items]
Schedule of Derivative Positions	Natural Gas Collars At June 30, 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) Third Quarter 2015 240,000 $ 4.25 $ 3.79 Fourth Quarter 2015 200,000 $ 4.25 $ 3.85 Calendar Year 2016 600,000 $ 4.25 $ 3.89 Total 1,040,000 Average price $ 4.25 $ 3.86 At December 31, 2014 , the Company had the following derivatives related to natural gas purchases in its specialty products segment, none of which are designated as hedges. Natural Gas Collars by Expiration Dates MMBtu Average Bought Call ($/MMBtu) Average Sold Put ($/MMBtu) First Quarter 2015 240,000 $ 4.25 $ 3.79 Second Quarter 2015 240,000 $ 4.25 $ 3.79 Third Quarter 2015 240,000 $ 4.25 $ 3.79 Fourth Quarter 2015 200,000 $ 4.25 $ 3.85 Calendar Year 2016 600,000 $ 4.25 $ 3.89 Total 1,520,000 Average price $ 4.25 $ 3.84
Fuel Product [Member] | Natural Gas Swap Contracts [Member]
Derivative [Line Items]
Schedule of Derivative Positions	At June 30, 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 Calendar Year 2016 1,320,000 $ 3.38 Total 1,320,000 Average price $ 3.38
Fuel Product [Member] | Crude Oil Swaps [Member]
Derivative [Line Items]
Schedule of Derivative Positions	Crude Oil Swap Contracts At June 30, 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 Third Quarter 2015 955,000 10,380 $ 58.96 Fourth Quarter 2015 185,000 2,011 $ 61.48 Calendar Year 2016 720,288 1,968 $ 62.71 Total 1,860,288 Average price $ 60.66 At June 30, 2015 , 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 Third Quarter 2015 120,000 1,304 $ 38.75 Total 120,000 Average price $ 38.75 At December 31, 2014 , the Company had the following derivatives related to crude oil purchases in its fuel products segment, all of which are designated as cash flow hedges. Crude Oil Swap Contracts by Expiration Dates Barrels Purchased BPD Average Swap First Quarter 2015 315,000 3,500 $ 97.71 Total 315,000 Average price $ 97.71 At December 31, 2014 , the Company had the following derivatives related to crude oil purchases in its fuel products segment, none of which are designated as hedges. Crude Oil Swap Contracts by Expiration Dates Barrels Purchased BPD Average Swap First Quarter 2015 1,674,000 18,600 $ 89.55 Second Quarter 2015 91,000 1,000 $ 89.89 Third Quarter 2015 386,400 4,200 $ 69.20 Fourth Quarter 2015 386,400 4,200 $ 69.20 Calendar Year 2016 972,828 2,658 $ 78.02 Total 3,510,628 Average price $ 81.89 At December 31, 2014 , the Company had the following derivatives related to crude oil sales in its fuel products segment, none of which are designated as hedges. Crude Oil Swap Contracts by Expiration Dates Barrels Sold BPD Average Swap First Quarter 2015 1,674,000 18,600 $ 84.21 Total 1,674,000 Average price $ 84.21
Fuel Product [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 Canadian heavy crude oil and NYMEX WTI crude oil, pricing differentials between LLS and NYMEX WTI and pricing differentials between MSW and NYMEX WTI. At December 31, 2014 , the Company had the following derivatives related to crude oil basis swaps in its fuel products segment, none of which are designated as hedges. Crude Oil Basis Swap Contracts by Expiration Dates Barrels Purchased BPD Average Differential to NYMEX WTI First Quarter 2015 118,000 2,000 $ (22.40 ) Total 118,000 Average differential $ (22.40 )
Fuel Product [Member] | Crude Oil Percent Basis Swaps [Member]
Derivative [Line Items]
Schedule of Derivative Positions	Crude Oil Percentage Basis Swap Contracts The Company entered into derivative instruments to secure a percentage differential on WCS crude oil to NYMEX WTI. At June 30, 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 Third Quarter 2015 184,000 2,000 73.0 % Fourth Quarter 2015 184,000 2,000 73.0 % Calendar Year 2016 732,000 2,000 75.0 % Total 1,100,000 Average percentage 74.3 % At December 31, 2014 , the Company had the following derivatives related to crude oil percentage basis swaps in its fuel products segment, none of which are designated as hedges. Crude Oil Percentage Basis Swap Contracts by Expiration Dates Barrels Purchased BPD Fixed Percentage of NYMEX WTI Third Quarter 2015 184,000 2,000 73.0 % Fourth Quarter 2015 184,000 2,000 73.0 % Total 368,000 Average percentage 73.0 %
Fuel Product [Member] | Crude Option Contracts [Member]
Derivative [Line Items]
Schedule of Derivative Positions	Crude Oil Option Contracts During the first quarter of 2015, the Company entered into derivative instruments to mitigate the risk of future changes in the price of NYMEX WTI crude oil. At June 30, 2015 , the Company had the following derivatives related to crude oil options bought 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) Third Quarter 2015 200,000 2,174 $ 53.50 Fourth Quarter 2015 300,000 3,261 $ 54.33 Calendar Year 2016 100,000 273 $ 55.00 Total 600,000 Average price $ 54.17 At June 30, 2015 , the Company had the following derivatives related to crude oil options sold 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) Third Quarter 2015 120,000 1,304 $ 64.71 Fourth Quarter 2015 800,000 8,696 $ 67.63 Calendar Year 2016 100,000 273 $ 65.00 Totals 1,020,000 Average price $ 67.02
Fuel Product [Member] | Diesel Swaps [Member]
Derivative [Line Items]
Schedule of Derivative Positions	Diesel Swap Contracts At June 30, 2015 , the Company had the following derivatives related to diesel sales in its fuel products segment, none of which are designated as hedges. Diesel Swap Contracts by Expiration Dates Barrels Sold BPD Average Swap ($/Bbl) Third Quarter 2015 92,000 1,000 $ 82.07 Fourth Quarter 2015 92,000 1,000 $ 82.07 Calendar Year 2016 549,000 1,500 $ 82.28 Total 733,000 Average price $ 82.22 At December 31, 2014 , the Company had the following derivatives related to diesel sales in its fuel products segment, none of which are designated as hedges. Diesel Swap Contracts by Expiration Dates Barrels Sold BPD Average Swap ($/Bbl) First Quarter 2015 1,449,000 16,100 $ 116.27 Second Quarter 2015 91,000 1,000 $ 117.92 Third Quarter 2015 322,000 3,500 $ 95.04 Fourth Quarter 2015 322,000 3,500 $ 95.04 Calendar Year 2016 915,000 2,500 $ 104.32 Total 3,099,000 Average price $ 108.38 At December 31, 2014 , the Company had the following derivatives related to diesel purchases in its fuel products segment, none of which are designated as hedges. Diesel Swap Contracts by Expiration Dates Barrels Purchased BPD Average Swap ($/Bbl) First Quarter 2015 1,449,000 16,100 $ 105.78 Total 1,449,000 Average price $ 105.78
Fuel Product [Member] | Diesel Percent Basis Crack Spread Swaps [Member]
Derivative [Line Items]
Schedule of Derivative Positions	Diesel Percentage Basis Crack Spread Swap Contracts At June 30, 2015 , the Company had the following diesel percentage basis crack spread swap contracts in its fuel products segment, none of which are designated as hedges. Diesel Percentage Basis Crack Spread Swap Contracts by Expiration Dates Barrels Sold BPD Fixed Percentage of NYMEX WTI Third Quarter 2015 46,000 500 32.5 % Fourth Quarter 2015 46,000 500 32.5 % Calendar Year 2016 2,196,000 6,000 31.8 % Total 2,288,000 Average percentage 31.8 % At December 31, 2014 , the Company had the following diesel percentage basis crack spread swap contracts in its fuel products segment, none of which are designated as hedges. Diesel Percentage Basis Crack Spread Swap Contracts by Expiration Dates Barrels Sold BPD Fixed Percentage of NYMEX WTI Third Quarter 2015 414,000 4,500 33.2 % Fourth Quarter 2015 414,000 4,500 33.2 % Calendar Year 2016 1,647,000 4,500 31.7 % Total 2,475,000 Average percentage 32.2 %
Fuel Product [Member] | Diesel Crack Spread Swaps [Member]
Derivative [Line Items]
Schedule of Derivative Positions	Diesel Crack Spread Swaps At June 30, 2015 , the Company had the following derivatives related to diesel crack spreads in its fuel products segment, none of which are designated as hedges. Diesel Crack Spread Swap Contracts by Expiration Dates Barrels Sold BPD Average Swap Third Quarter 2015 598,000 6,500 $ 20.38 Fourth Quarter 2015 598,000 6,500 $ 20.38 Total 1,196,000 Average price $ 20.38
Fuel Product [Member] | Jet Fuel Swap Contracts [Member]
Derivative [Line Items]
Schedule of Derivative Positions	Jet Fuel Swap Contracts At December 31, 2014 , the Company had the following derivatives related to jet fuel sales in its fuel products segment, none of which are designated as cash flow hedges. Jet Fuel Swap Contracts by Expiration Dates Barrels Sold BPD Average Swap ($/Bbl) First Quarter 2015 180,000 2,000 $ 115.65 Total 180,000 Average price $ 115.65 At December 31, 2014 , the Company had the following derivatives related to jet fuel purchases in its fuel products segment, none of which are designated as hedges. Jet Fuel Swap Contracts by Expiration Dates Barrels Purchased BPD Average Swap ($/Bbl) First Quarter 2015 180,000 2,000 $ 100.91 Total 180,000 Average price $ 100.91
Fuel Product [Member] | Gasoline Swap Contracts [Member]
Derivative [Line Items]
Schedule of Derivative Positions	Gasoline Swap Contracts At June 30, 2015 , the Company had the following derivatives related to gasoline sales in its fuel products segment, none of which are designated as hedges. Gasoline Swap Contracts by Expiration Dates Barrels Sold BPD Average Swap ($/Bbl) Third Quarter 2015 863,000 9,380 $ 74.60 Fourth Quarter 2015 93,000 1,011 $ 70.53 Total 956,000 Average price $ 74.21 At December 31, 2014 , the Company had the following derivatives related to gasoline sales in its fuel products segment, all of which are designated as cash flow hedges. Gasoline Swap Contracts by Expiration Dates Barrels Sold BPD Average Swap ($/Bbl) First Quarter 2015 315,000 3,500 $ 109.68 Total 315,000 Average price $ 109.68 At December 31, 2014 , the Company had the following derivatives related to gasoline sales in its fuel products segment, none of which are designated as hedges. Gasoline Swap Contracts by Expiration Dates Barrels Sold BPD Average Swap ($/Bbl) First Quarter 2015 45,000 500 $ 111.72 Total 45,000 Average price $ 111.72 At December 31, 2014 , the Company had the following derivatives related to gasoline purchases in its fuel products segment, none of which are designated as hedges. Gasoline Swap Contracts by Expiration Dates Barrels Purchased BPD Average Swap ($/Bbl) First Quarter 2015 45,000 500 $ 78.12 Total 45,000 Average price $ 78.12
Fuel Product [Member] | Gasoline Crack Spread Swaps [Member]
Derivative [Line Items]
Schedule of Derivative Positions	Gasoline Crack Spread Swaps At June 30, 2015 , the Company had the following derivatives related to gasoline crack spreads 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 Third Quarter 2015 491,000 5,337 $ 15.65 Fourth Quarter 2015 705,500 7,668 $ 7.93 Total 1,196,500 Average price $ 11.10
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 June 30, 2015 and 2014 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 Income (Loss) on Derivatives (Effective Portion) Amount of Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (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 June 30, June 30, June 30, 2015 2014 2015 2014 2015 2014 Fuel products segment: Crude oil swaps $ (2.7 ) $ 53.5 Cost of sales $ (53.2 ) $ 13.6 Unrealized/ Realized $ — $ 30.3 Gasoline swaps 2.7 (8.2 ) Sales 19.3 (5.8 ) Unrealized/ Realized — (3.6 ) Diesel swaps (1.4 ) (33.4 ) Sales 39.8 (4.9 ) Unrealized/ Realized — (1.6 ) Jet fuel swaps 0.3 (3.8 ) Sales 4.0 (0.9 ) Unrealized/ Realized — (0.5 ) Specialty products segment: Crude oil swaps — — Cost of sales 1.6 (0.9 ) Unrealized/ Realized — — Total $ (1.1 ) $ 8.1 $ 11.5 $ 1.1 $ — $ 24.6 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 six months ended June 30, 2015 and 2014 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 Income (Loss) on Derivatives (Effective Portion) Amount of Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) into Net Income (Loss) (Effective Portion) Amount of Gain (Loss) Recognized in Net Income (Loss) on Derivatives (Ineffective Portion) Six Months Ended Location of Gain (Loss) Six Months Ended Location of Gain (Loss) Six Months Ended June 30, June 30, June 30, 2015 2014 2015 2014 2015 2014 Fuel products segment: Crude oil swaps $ (9.0 ) $ 71.2 Cost of sales $ (74.7 ) $ 23.1 Unrealized/ Realized $ (0.2 ) $ 47.7 Gasoline swaps 3.5 (10.0 ) Sales 33.3 (11.5 ) Unrealized/ Realized 0.7 (4.5 ) Diesel swaps (1.3 ) (13.4 ) Sales 44.6 (11.1 ) Unrealized/ Realized — (0.1 ) Jet fuel swaps 0.6 2.7 Sales 5.4 (2.1 ) Unrealized/ Realized — (0.4 ) Specialty products segment: Crude oil swaps — — Cost of sales 1.2 (1.2 ) Unrealized/ Realized — — Total $ (6.2 ) $ 50.5 $ 9.8 $ (2.8 ) $ 0.5 $ 42.7
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 June 30, 2015 and 2014 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 June 30, Three Months Ended June 30, 2015 2014 2015 2014 Fuel products segment: Crude oil swaps $ 7.7 $ 10.5 $ 5.2 $ 11.1 Crude oil basis swaps — 0.6 2.2 (1.8 ) Gasoline swaps (16.4 ) (7.6 ) (7.1 ) (1.5 ) Diesel swaps 1.2 (1.6 ) (3.8 ) (5.5 ) Diesel crack spread swaps — — 7.4 — Gasoline crack spread swaps (3.9 ) — (1.7 ) — Jet fuel swaps — (0.1 ) — — Diesel crack spread collars — 0.6 — — Platinum swaps — — (0.2 ) — Natural gas swaps — — — — Gasoline crack spread collars — — — (0.5 ) Specialty products segment: Natural gas swaps (2.5 ) 0.4 3.1 0.4 Total $ (13.9 ) $ 2.8 $ 5.1 $ 2.2 The Company recorded the following gains (losses) in its unaudited condensed consolidated statements of operations for the six months ended June 30, 2015 and 2014 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 Six Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 Fuel products segment: Crude oil swaps $ (40.6 ) $ 14.4 $ 55.4 $ 14.5 Crude oil basis swaps 1.0 1.2 1.8 (0.5 ) Gasoline swaps (18.4 ) (11.2 ) (8.2 ) 1.0 Diesel swaps 59.2 (1.6 ) (67.2 ) (2.5 ) Diesel crack spread swaps 0.9 — 1.0 — Gasoline crack spread swaps (4.7 ) — (3.2 ) — Jet fuel swaps 1.6 (0.5 ) (1.6 ) (0.9 ) Diesel crack spread collars — 1.0 — 0.4 Platinum swaps — — (0.3 ) — Natural gas swaps — — (0.3 ) — Gasoline crack spread collars — — — 0.2 Specialty products segment: Natural gas swaps (4.6 ) 1.3 (0.1 ) 1.3 Total $ (5.6 ) $ 4.6 $ (22.7 ) $ 13.5
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 and six months ended June 30, 2015 and 2014 related to its derivative instrument designated as a fair value hedge (in millions): Location of Gain (Loss) of Derivative Amount of Loss Recognized in Net Income (Loss) Hedged Item Location of Gain (Loss) on Hedged Item Amount of Gain Recognized in Net Income (Loss) Three Months Ended June 30, Six Months Ended June 30, Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 2015 2014 2015 2014 Swaps not allocated to a specific segment: Interest rate swap Interest income (expense) $ — $ 1.0 $ — $ (0.6 ) 2022 Notes Interest income (expense) $ — $ (1.0 ) $ — $ 0.6 Total $ — $ 1.0 $ — $ (0.6 ) $ — $ (1.0 ) $ — $ 0.6

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	6 Months Ended
	Jun. 30, 2015
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 June 30, 2015 and December 31, 2014 were as follows (in millions): June 30, 2015 December 31, 2014 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets: Derivative assets: Crude oil swaps $ — $ — $ (0.6 ) $ (0.6 ) $ — $ — $ (89.8 ) $ (89.8 ) Crude oil basis swaps — — — — — — 0.8 0.8 Crude oil percentage basis swaps — — — — — — (0.2 ) (0.2 ) Gasoline swaps — — — — — — 13.5 13.5 Diesel swaps — — 0.7 0.7 — — 97.0 97.0 Diesel crack spread swaps — — 1.6 1.6 — — 4.5 4.5 Jet fuel swaps — — — — — — 2.7 2.7 Natural gas swaps — — (0.5 ) (0.5 ) — — (7.2 ) (7.2 ) Natural gas collars — — — — — — (0.5 ) (0.5 ) Platinum swaps — — — — — — (0.1 ) (0.1 ) Interest rate swaps — — — — — — 2.5 2.5 Total derivative assets — — 1.2 1.2 — — 23.2 23.2 Pension plan investments 0.5 48.1 — 48.6 0.2 49.4 — 49.6 Total recurring assets at fair value $ 0.5 $ 48.1 $ 1.2 $ 49.8 $ 0.2 $ 49.4 $ 23.2 $ 72.8 Liabilities: Derivative liabilities: Crude oil swaps $ — $ — $ (0.2 ) $ (0.2 ) $ — $ — $ 5.0 $ 5.0 Crude oil percentage basis swaps — — 2.3 2.3 — — — — Gasoline swaps — — (7.5 ) (7.5 ) — — 3.8 3.8 Gasoline crack spread swaps — — (3.2 ) (3.2 ) — — — — Diesel swaps — — 0.8 0.8 — — (9.0 ) (9.0 ) Diesel crack spread swaps — — 4.0 4.0 — — — — Natural gas swaps — — (12.2 ) (12.2 ) — — (4.9 ) (4.9 ) Natural gas collars — — (0.9 ) (0.9 ) — — (0.5 ) (0.5 ) Platinum swaps — — (0.4 ) (0.4 ) — — — — Crude oil options — — (1.0 ) (1.0 ) — — — — Total derivative liabilities — — (18.3 ) (18.3 ) — — (5.6 ) (5.6 ) RINs Obligation — (41.5 ) — (41.5 ) — (16.3 ) — (16.3 ) Liability Awards (6.4 ) — — (6.4 ) (4.7 ) — — (4.7 ) Total recurring liabilities at fair value $ (6.4 ) $ (41.5 ) $ (18.3 ) $ (66.2 ) $ (4.7 ) $ (16.3 ) $ (5.6 ) $ (26.6 )
Summary of Net Changes in Fair Value of the Company's Level 3 Financial Assets and Liabilities	The table below sets forth a summary of net changes in fair value of the Company’s Level 3 financial assets and liabilities for the six months ended June 30, 2015 and 2014 (in millions): Six Months Ended June 30, 2015 2014 Fair value at January 1, $ 17.6 $ (54.8 ) Realized (gain) loss on derivative instruments 5.1 (12.6 ) Unrealized gain (loss) on derivative instruments (22.7 ) 48.2 Interest expense, net (0.3 ) (1.9 ) Change in fair value of cash flow hedges (6.2 ) 50.5 Settlements (10.6 ) 12.9 Transfers in (out) of Level 3 — — Fair value at June 30, $ (17.1 ) $ 42.3 Total gain (loss) included in net income (loss) attributable to changes in unrealized gain (loss) relating to financial assets and liabilities held as of June 30, $ (22.7 ) $ 48.2
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 June 30, 2015 and December 31, 2014 were as follows (in millions): June 30, 2015 December 31, 2014 Level Fair Value Carrying Value Fair Value Carrying Value Financial Instrument: Senior notes 1 $ 1,252.1 $ 1,248.5 $ 630.0 $ 619.1 Senior notes 2 $ 333.9 $ 322.6 $ 803.3 $ 900.0 Revolving credit facility 3 $ 103.1 $ 103.1 $ 150.8 $ 150.8 Capital lease and other obligations 3 $ 43.4 $ 43.4 $ 43.6 $ 43.6

Employee Benefit Plans (Tables)

Employee Benefit Plans (Tables)	6 Months Ended
	Jun. 30, 2015
Compensation and Retirement Disclosure [Abstract]
Summary of Components of Net Periodic Pension Cost	The components of net periodic pension cost for the three and six months ended June 30, 2015 and 2014 were as follows (in millions): Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 Service cost $ 0.2 $ 0.1 $ 0.3 $ 0.2 Interest cost 0.6 0.6 1.3 1.3 Expected return on assets (0.9 ) (0.7 ) (1.7 ) (1.5 ) Amortization of net loss 0.2 — 0.4 0.2 Net periodic benefit cost $ 0.1 $ — $ 0.3 $ 0.2
Schedule of Pension Plan Assets Measured at Fair Value	The Company’s pension plan assets measured at fair value at June 30, 2015 and December 31, 2014 were as follows (in millions): June 30, 2015 December 31, 2014 Level 1 Level 2 Level 1 Level 2 Cash and cash equivalents $ 0.5 $ — $ 0.2 $ — Domestic equities — 9.7 — 10.0 Foreign equities — 9.5 — 9.4 Fixed income — 28.9 — 30.0 $ 0.5 $ 48.1 $ 0.2 $ 49.4

Accumulated Other Comprehensi31

Accumulated Other Comprehensive Income (Tables)	6 Months Ended
	Jun. 30, 2015
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 and six months ended June 30, 2015 and 2014 (in millions): Components of Accumulated Other Comprehensive Income (Loss) Amount Reclassified From Accumulated Other Comprehensive Income (Loss) Location of Gain (Loss) Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 Derivative gains (losses) on cash flow hedges: $ 63.1 $ (11.6 ) $ 83.3 $ (24.7 ) Sales (51.6 ) 12.7 (73.5 ) 21.9 Cost of sales $ 11.5 $ 1.1 $ 9.8 $ (2.8 ) Total Amortization of defined benefit pension and postretirement health benefit plans: Amortization of net loss $ (0.2 ) $ — $ (0.4 ) $ (0.2 ) (1) $ (0.2 ) $ — $ (0.4 ) $ (0.2 ) Total (1) This accumulated other comprehensive income (loss) component is included in the computation of net periodic pension cost. See Note 11 for additional details.

Earnings Per Unit (Tables)

Earnings Per Unit (Tables)	6 Months Ended
	Jun. 30, 2015
Earnings Per Unit [Abstract]
Summary of Computation of Basic and Diluted Earnings Per Limited Partner Unit	The following table sets forth the computation of basic and diluted earnings per limited partner unit for the three and six months ended June 30, 2015 and 2014 (in millions, except unit and per unit data): Three Months Ended Six Months Ended June 30, June 30, 2015 2014 2015 2014 Numerator for basic and diluted earnings per limited partner unit: Net income (loss) $ 2.5 $ (8.3 ) $ 26.3 $ (58.1 ) General partner’s interest in net income (loss) — (0.2 ) 0.5 (1.2 ) General partner’s incentive distribution rights 4.2 3.9 8.4 7.7 Non-vested share based payments — — — — Net income (loss) available to limited partners $ (1.7 ) $ (12.0 ) $ 17.4 $ (64.6 ) Denominator for basic and diluted earnings per limited partner unit: Basic weighted average limited partner units outstanding 76,092,517 69,604,669 73,675,251 69,614,055 Effect of dilutive securities: Participating securities — phantom units — — 54,938 — Diluted weighted average limited partner units outstanding (1) 76,092,517 69,604,669 73,730,189 69,614,055 Limited partners’ interest basic and diluted net income (loss) per unit $ (0.02 ) $ (0.17 ) $ 0.23 $ (0.93 ) (1) Total diluted weighted average limited partner units outstanding excludes 0.1 million of dilutive phantom units for the three months ended June 30, 2015 . Total diluted weighted average limited partner units outstanding excludes 0.2 million and 0.1 million of dilutive phantom units for the three and six months ended June 30, 2014 , respectively.

Segments and Related Informat33

Segments and Related Information (Tables)	6 Months Ended
	Jun. 30, 2015
Segment Reporting [Abstract]
Schedule of Reportable Segment Information	Reportable segment information for the three and six months ended June 30, 2015 and 2014 is as follows (in millions): Three Months Ended June 30, 2015 Specialty Products Fuel Products Oilfield Services Combined Segments Eliminations Consolidated Total Sales: External customers $ 370.6 $ 715.1 $ 70.5 $ 1,156.2 $ — $ 1,156.2 Intersegment sales 1.7 12.1 — 13.8 (13.8 ) — Total sales $ 372.3 $ 727.2 $ 70.5 $ 1,170.0 $ (13.8 ) $ 1,156.2 Adjusted EBITDA $ 59.1 $ 50.1 $ (14.2 ) $ 95.0 $ — $ 95.0 Reconciling items to net income: Depreciation and amortization 16.7 20.2 5.7 42.6 — 42.6 Realized loss on derivatives, not reflected in net income or settled in a prior period (1.6 ) (11.0 ) — (12.6 ) — (12.6 ) Unrealized gain on derivatives (5.2 ) Interest expense 27.4 Debt extinguishment costs 46.6 Non-cash equity based compensation and other non-cash items 2.8 Income tax benefit (9.1 ) Net income $ 2.5 Three Months Ended June 30, 2014 Specialty Products Fuel Products Oilfield Services Combined Segments Eliminations Consolidated Total Sales: External customers $ 424.4 $ 900.7 $ 109.8 $ 1,434.9 $ — $ 1,434.9 Intersegment sales 7.2 27.9 — 35.1 (35.1 ) — Total sales $ 431.6 $ 928.6 $ 109.8 $ 1,470.0 $ (35.1 ) $ 1,434.9 Adjusted EBITDA $ 34.3 $ (3.1 ) $ 8.1 $ 39.3 $ — $ 39.3 Reconciling items to net loss: Depreciation and amortization 16.7 20.3 4.5 41.5 — 41.5 Realized gain on derivatives, not reflected in net loss or settled in a prior period 0.9 1.0 — 1.9 — 1.9 Unrealized gain on derivatives (23.6 ) Interest expense 28.7 Non-cash equity based compensation and other non-cash items 1.0 Income tax benefit (1.9 ) Net loss $ (8.3 ) Six Months Ended June 30, 2015 Specialty Products Fuel Products Oilfield Services Combined Segments Eliminations Consolidated Total Sales: External customers $ 732.2 $ 1,283.4 $ 159.2 $ 2,174.8 $ — $ 2,174.8 Intersegment sales 3.0 25.0 — 28.0 (28.0 ) — Total sales $ 735.2 $ 1,308.4 $ 159.2 $ 2,202.8 $ (28.0 ) $ 2,174.8 Adjusted EBITDA $ 120.7 $ 117.5 $ (18.3 ) $ 219.9 $ — $ 219.9 Reconciling items to net income: Depreciation and amortization 32.6 40.2 11.3 84.1 — 84.1 Realized loss on derivatives, not reflected in net income or settled in a prior period (1.2 ) (5.3 ) — (6.5 ) — (6.5 ) Unrealized loss on derivatives 22.7 Interest expense 54.4 Debt extinguishment costs 46.6 Non-cash equity based compensation and other non-cash items 6.2 Income tax benefit (13.9 ) Net income $ 26.3 Six Months Ended June 30, 2014 Specialty Products Fuel Products Oilfield Services Combined Segments Eliminations Consolidated Total Sales: External customers $ 874.4 $ 1,791.7 $ 109.8 $ 2,775.9 $ — $ 2,775.9 Intersegment sales 7.2 45.1 — 52.3 (52.3 ) — Total sales $ 881.6 $ 1,836.8 $ 109.8 $ 2,828.2 $ (52.3 ) $ 2,775.9 Adjusted EBITDA $ 92.0 $ 21.9 $ 8.1 $ 122.0 $ — $ 122.0 Reconciling items to net loss: Depreciation and amortization 33.4 39.6 4.5 77.5 — 77.5 Realized gain on derivatives, not reflected in net loss or settled in a prior period 1.2 2.2 — 3.4 — 3.4 Unrealized gain on derivatives (48.2 ) Interest expense 54.9 Debt extinguishment costs 89.6 Non-cash equity based compensation and other non-cash items 4.6 Income tax benefit (1.7 ) Net loss $ (58.1 )
Schedule of Major Product Category Sales	The following table sets forth the major product category sales for the three months ended June 30, 2015 and 2014 (in millions): Three Months Ended June 30, 2015 2014 Specialty products: Lubricating oils $ 158.1 13.7 % $ 184.4 12.9 % Solvents 81.6 7.1 % 120.6 8.4 % Waxes 33.9 2.9 % 30.9 2.2 % Packaged and synthetic specialty products 88.4 7.6 % 79.8 5.6 % Other 8.6 0.8 % 8.7 0.5 % Total $ 370.6 32.1 % $ 424.4 29.6 % Fuel products: Gasoline $ 302.6 26.2 % $ 358.3 25.0 % Diesel 251.0 21.7 % 268.0 18.7 % Jet fuel 37.9 3.3 % 42.1 2.9 % Asphalt, heavy fuel oils and other 123.6 10.7 % 232.3 16.2 % Total $ 715.1 61.9 % $ 900.7 62.8 % Oilfield services: Total $ 70.5 6.0 % $ 109.8 7.6 % Consolidated sales $ 1,156.2 100.0 % $ 1,434.9 100.0 % The following table sets forth the major product category sales for the six months ended June 30, 2015 and 2014 (in millions): Six Months Ended June 30, 2015 2014 Specialty products: Lubricating oils $ 307.9 14.2 % $ 382.1 13.8 % Solvents 167.8 7.7 % 252.0 9.1 % Waxes 72.9 3.4 % 66.3 2.4 % Packaged and synthetic specialty products 168.9 7.8 % 156.2 5.6 % Other 14.7 0.7 % 17.8 0.6 % Total $ 732.2 33.8 % $ 874.4 31.5 % Fuel products: Gasoline $ 548.9 25.1 % $ 717.9 25.9 % Diesel 464.9 21.4 % 585.4 21.1 % Jet fuel 76.1 3.5 % 86.1 3.1 % Asphalt, heavy fuel oils and other 193.5 8.9 % 402.3 14.4 % Total $ 1,283.4 58.9 % $ 1,791.7 64.5 % Oilfield services: Total $ 159.2 7.3 % $ 109.8 4.0 % Consolidated sales $ 2,174.8 100.0 % $ 2,775.9 100.0 %

Description of the Business - N

Description of the Business - Narrative (Details) - shares	6 Months Ended
	Jun. 30, 2015	Dec. 31, 2014
Limited Partner [Member]
Schedule of Equity Method Investments [Line Items]
Limited partner common units outstanding (in shares)	75,760,218	69,452,233
Ownership percentage	98.00%
General Partner [Member]
Schedule of Equity Method Investments [Line Items]
General partner equivalent units outstanding (in shares)	1,546,126
Ownership percentage	2.00%

Summary of Significant Accoun35

Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Details) - USD ($) $ in Millions	6 Months Ended	12 Months Ended
	Jun. 30, 2015	Dec. 31, 2014
Debt Disclosure [Abstract]
Amortization of Financing Costs	$ 32.3	$ 34.7

Acquisitions - Narrative (Detai

Acquisitions - Narrative (Details) - USD ($) $ in Millions	Mar. 31, 2014	Jun. 30, 2015	Aug. 01, 2014	Jun. 30, 2014	Feb. 28, 2014
Business Acquisition [Line Items]
Percent payment required of post-closing taxes		50.00%
SOS Acquisition [Member]
Business Acquisition [Line Items]
Aggregate consideration			$ 29.6
Anchor Acquisition [Member]
Business Acquisition [Line Items]
Aggregate consideration				$ 223.6
Estimated post-closing taxes		$ 1
United Acquisition [Member]
Business Acquisition [Line Items]
Aggregate consideration					$ 10.4
Notes Due April 2021 at Fixed Rate of 6.5% Interest Payments [Member]
Business Acquisition [Line Items]
Net proceeds from debt	$ 884
Maturity date	Apr. 15, 2021

Acquisitions - Summary of Sales

Acquisitions - Summary of Sales and Operating Income and Unaudited Pro Forma Financial Information (Details) - USD ($) $ / shares in Units, $ in Millions	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
Result of Sales and Operating Income [Abstract]
Sales	$ 151.5
Operating loss	$ (24.3)
Unaudited Pro Forma Financial Information [Abstract]
Sales		$ 2,858.4
Net loss		$ (64.3)
Limited partners’ interest net loss per unit — basic and diluted (in USD per share)		$ (1.02)

Inventories - Narrative (Detail

Inventories - Narrative (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Inventory Disclosure [Abstract]
Inventory method			last-in, first-out (“LIFO”)
Replacement cost of inventories, based on current market values	$ 50.9		$ 50.9		$ 18.9
Lower of cost or market inventory adjustment	$ (12.4)	$ (1.6)	$ (0.8)	$ 2.9

Inventories - Summary of Invent

Inventories - Summary of Inventories (Details) - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
Inventories
Raw materials	$ 100.8	$ 77.8
Work in process	80.1	75.4
Finished goods	372.4	360.3
Inventories total	$ 553.3	$ 513.5

Investment in Unconsolidated 40

Investment in Unconsolidated Affiliates - Narrative (Details) - USD ($) $ in Millions	Jun. 09, 2014	Feb. 07, 2013	Jun. 30, 2015	Dec. 31, 2014
Schedule of Equity Method Investments [Line Items]
Investment in unconsolidated affiliates			$ 170.6	$ 137.3
Juniper GTL LLC [Member]
Schedule of Equity Method Investments [Line Items]
Ownership percentage in entity	100.00%
Juniper GTL LLC [Member] | Management [Member]
Schedule of Equity Method Investments [Line Items]
Equity ownership percentage in entity	10.00%
Dakota Prairie Refining, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity interest percentage		50.00%
Investment in unconsolidated affiliates			144.6	117.2
Dakota Prairie Refining, LLC [Member] | Proceeds From Term Loan [Member]
Schedule of Equity Method Investments [Line Items]
Contribution amount funded		$ 75
Juniper GTL LLC [Member]
Schedule of Equity Method Investments [Line Items]
Contribution amount funded	$ 25
Equity interest percentage	23.00%
Investment in unconsolidated affiliates			$ 24.6	$ 18.5
Juniper GTL LLC [Member] | Proceeds From Term Loan [Member]
Schedule of Equity Method Investments [Line Items]
Contribution amount funded	$ 35
Juniper GTL LLC [Member] | Cash Contributions [Member]
Schedule of Equity Method Investments [Line Items]
Contribution amount funded	$ 100

Investment in Unconsolidated 41

Investment in Unconsolidated Affiliates Investment in Unconsolidated Affiliates - DPR Summary Financials (Details) - Dakota Prairie Refining, LLC [Member] - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Summarized Financial Information, Revenue	$ 48.4	$ 0	$ 50.1	$ 0
Equity Method Investment, Summarized Financial Information, Operating Revenue	(14.8)	(1.6)	(21.8)	(2.6)
Equity Method Investment, Summarized Financial Information, Net Income (Loss)	$ (15.2)	$ (1.6)	$ (22.3)	$ (2.6)

Commitments and Contingencies -

Commitments and Contingencies - Narrative - Environmental (Details) - USD ($) $ in Millions	Jul. 01, 2015	Jun. 29, 2012	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Montana [Member]
Loss Contingencies [Line Items]
Environmental remediation expense					$ 17.8
MDEQ [Member]
Loss Contingencies [Line Items]
Proposed penalty amount	$ 0.1
WDNR-Superior [Member]
Loss Contingencies [Line Items]
Environmental remediation expense			$ 0	$ 0.1	0	$ 0.5
Estimates Costs of Equipment Upgrades and Conduct Other Discrete					1
EPA [Member]
Loss Contingencies [Line Items]
Proposed penalty amount		$ 0.1
LDEQ-Shreveport, Cotton Valley & Princeton [Member]
Loss Contingencies [Line Items]
Environmental remediation expense			1.4	$ 0.1	$ 2.4	$ 0.2
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			$ 0.7		0.7
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					3.2
Minimum [Member] | LDEQ-Shreveport, Cotton Valley & Princeton [Member]
Loss Contingencies [Line Items]
Environmental remediation expense					7
Maximum [Member] | LDEQ-Shreveport, Cotton Valley & Princeton [Member]
Loss Contingencies [Line Items]
Environmental remediation expense					9
Maximum [Member] | Shreveport [Member]
Loss Contingencies [Line Items]
Specified environmental liabilities first required amount to contribute					$ 1

Commitments and Contingencies43

Commitments and Contingencies - Narrative - Occupational Health and Safety (Details) - Occupational Safety and Health Administration [Member] - USD ($) $ in Millions	Mar. 14, 2011	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Loss Contingencies [Line Items]
Capital expenditures		$ 0.2	$ 0.3	$ 0.3	$ 0.5
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) - Revolving Credit Facility [Member] - USD ($)	Jun. 30, 2015	Dec. 31, 2014
Loss Contingencies [Line Items]
Outstanding standby letters of credit	$ 99,100,000	$ 114,300,000
Letters of credit available to issue	423,200,000	$ 310,800,000
Maximum [Member]
Loss Contingencies [Line Items]
Letter of credit sublimit	$ 600,000,000
Letter of credit sublimit, percentage of revolver commitments	90.00%
Revolver commitments	$ 1,000,000,000

Long-Term Debt - Summary of Lon

Long-Term Debt - Summary of Long-Term Debt (Details) - USD ($) $ in Millions		Jan. 13, 2015	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Summary of Long-term debt
Total long-term debt			$ 1,717.6		$ 1,717.6		$ 1,713.5
Less current portion of long-term debt			0.6		0.6		0.6
Total long-term debt, excluding current portion			1,717		1,717		1,712.9
Revolving Credit Facility [Member]
Summary of Long-term debt
Borrowings under senior secured revolving credit agreement			$ 103.1		$ 103.1		150.8
Senior Notes [Abstract]
Weighted average interest rate			3.40%		3.40%
9.625% Notes [Member]
Summary of Long-term debt
Borrowings under Notes			$ 0		$ 0		275
Senior Notes [Abstract]
Fixed rate			9.625%		9.625%
Effective interest rate			10.10%		10.10%
Notes Due April 2021 at Fixed Rate of 6.5% Interest Payments [Member]
Summary of Long-term debt
Borrowings under Notes			$ 900		$ 900		900
Senior Notes [Abstract]
Fixed rate			6.50%		6.50%
Effective interest rate			6.70%		6.70%
7.625% Notes [Member]
Summary of Long-term debt
Borrowings under Notes	[1]		$ 353		$ 353		352.5
Senior Notes [Abstract]
Fixed rate			7.625%		7.625%
Effective interest rate			8.00%		8.00%
Notes Due April 2023 at Fixed Rate of 7.75% Interest Payments [Member]
Summary of Long-term debt
Borrowings under Notes			$ 325		$ 325		0
Senior Notes [Abstract]
Fixed rate			7.75%		7.75%
Effective interest rate			8.00%		8.00%
Less unamortized discounts [Member]
Summary of Long-term debt
Less unamortized discounts			$ (6.9)		$ (6.9)		(8.4)
Interest Expense [Member] | Fair Value Hedging [Member]
Senior Notes [Abstract]
Liabilities, fair value adjustment					3		$ 2.5
Designated as Hedging Instrument [Member] | Interest Expense [Member] | Interest Rate Swap [Member] | Fair Value Hedging [Member]
Senior Notes [Abstract]
Liabilities, fair value adjustment		$ 3.3	$ 0	$ (1)	$ 0	$ 0.6
[1]	The balance includes a fair value interest rate hedge adjustment, which increased the debt balance by $3.0 million and $2.5 million as of June 30, 2015 and December 31, 2014, respectively (refer to Note 8 for additional information on the interest rate swap designated as a fair value hedge at December 31, 2014).

Long-Term Debt - Narrative (Det

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

Apr. 28, 2015

Apr. 27, 2015

Mar. 27, 2015

Mar. 13, 2015

Mar. 31, 2014

Nov. 26, 2013

Jun. 29, 2012

Jun. 30, 2015

Jun. 30, 2014

Jun. 30, 2015

Jun. 30, 2014

Dec. 31, 2014

Long-Term Debt (Textual) [Abstract]

Common units sold (in shares)

6,000,000

307,985

Debt extinguishment costs

$ (46,600,000)

$ 0

$ (46,600,000)

$ (89,600,000)

Notes Due April 2023 at Fixed Rate of 7.75% Interest Payments [Member]

Debt Instrument [Line Items]

Debt Instrument, Interest Rate, Increase (Decrease)

1.00%

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

Redemption percentage up to

35.00%

Redemption price, percent

107.75%

Minimum percent of aggregate principal amount outstanding immediately after redemption

65.00%

Threshold period of redemption

180 days

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]

Date senior notes issued and sold

Jun. 29, 2012

Senior notes, aggregate principal amount issued and sold

$ 275,000,000

Maturity date

Aug. 1, 2020

Debt instrument percent discount price of par

98.25%

Net proceeds from sale of senior notes

$ 262,500,000

Redemption of aggregate principal amount

$ (178,800,000)

$ 96,200,000

Frequency of interest payment

semiannually

Senior Notes [Member]

Long-Term Debt (Textual) [Abstract]

Debt extinguishment costs

$ 46,600,000

Senior Notes [Member] | Maximum [Member]

Long-Term Debt (Textual) [Abstract]

Fixed charge coverage ratio

3.1

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

$ 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

625,300,000

$ 625,300,000

Outstanding borrowings

103,100,000

103,100,000

$ 150,800,000

Outstanding standby letters of credit

99,100,000

99,100,000

$ 114,300,000

Available for additional borrowings based on specified availability limitations

423,200,000

$ 423,200,000

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, 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

$ 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 Red

Long-Term Debt - Summary of Redemption Prices (Details) - Notes Due April 2023 at Fixed Rate of 7.75% Interest Payments [Member]	Mar. 27, 2015
April 15, 2018 through April 14, 2019 [Member]
Debt Instrument, Redemption [Line Items]
Redemption price, percentage	105.813%
April 15, 2019 through April 14, 2020 [Member]
Debt Instrument, Redemption [Line Items]
Redemption price, percentage	103.875%
April 15, 2020 through April 14, 2021 [Member]
Debt Instrument, Redemption [Line Items]
Redemption price, percentage	101.938%
April 15, 2021 & Thereafter [Member]
Debt Instrument, Redemption [Line Items]
Redemption price, percentage	100.00%

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	Jun. 30, 2015USD ($)
Maturities of long-term debt
2,015	$ 0.3
2,016	0.7
2,017	0.7
2,018	0.8
2,019	103.9
Thereafter	1,615.1
Long-term debt	$ 1,721.5

Derivatives - Summary of Gross

Derivatives - Summary of Gross Fair Values of Derivative Instruments, Presenting the Impact of Offsetting Derivative Assets (Details) - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	$ 13.2	$ 181.6
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	(12)	(158.4)
Net Amounts of Assets Presented in the Condensed Consolidated Balance Sheets	1.2	23.2
Designated as Hedging Instrument [Member]
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	0	18.4
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	0	(14.4)
Net Amounts of Assets Presented in the Condensed Consolidated Balance Sheets	0	4
Not Designated as Hedging Instrument [Member]
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	13.2	163.2
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	(12)	(144)
Net Amounts of Assets Presented in the Condensed Consolidated Balance Sheets	1.2	19.2
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	1.7	31.4
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	(2.3)	(111.2)
Net Amounts of Assets Presented in the Condensed Consolidated Balance Sheets	(0.6)	(79.8)
Commodity Contract [Member] | Gasoline Swaps [Member] | Not Designated as Hedging Instrument [Member] | Fuel Product [Member]
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	0	2.4
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	0	(0.4)
Net Amounts of Assets Presented in the Condensed Consolidated Balance Sheets	0	2
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	0	0.8
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	0	0
Net Amounts of Assets Presented in the Condensed Consolidated Balance Sheets	0	0.8
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	2.3	0
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	(2.3)	(0.2)
Net Amounts of Assets Presented in the Condensed Consolidated Balance Sheets	0	(0.2)
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	1.1	0
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	(1.1)	0
Net Amounts of Assets Presented in the Condensed Consolidated Balance Sheets	0	0
Commodity Contract [Member] | Gasoline Crack Spread Swaps [Member] | Not Designated as Hedging Instrument [Member] | Fuel Product [Member]
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	0.9	0
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	(0.9)	0
Net Amounts of Assets Presented in the Condensed Consolidated Balance Sheets	0	0
Commodity Contract [Member] | Diesel Swaps [Member] | Not Designated as Hedging Instrument [Member] | Fuel Product [Member]
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	1.6	116.1
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	(0.9)	(19.1)
Net Amounts of Assets Presented in the Condensed Consolidated Balance Sheets	0.7	97
Commodity Contract [Member] | Diesel Crack Spread Swaps [Member] | Not Designated as Hedging Instrument [Member] | Fuel Product [Member]
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	5.6	4.5
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	(4)	0
Net Amounts of Assets Presented in the Condensed Consolidated Balance Sheets	1.6	4.5
Commodity Contract [Member] | Jet Fuel Swaps [Member] | Not Designated as Hedging Instrument [Member] | Fuel Product [Member]
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	0	7.9
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	0	(5.2)
Net Amounts of Assets Presented in the Condensed Consolidated Balance Sheets	0	2.7
Commodity Contract [Member] | Natural Gas Swaps [Member] | Not Designated as Hedging Instrument [Member] | Specialty Product [Member]
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	0	0
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	(0.5)	(7.2)
Net Amounts of Assets Presented in the Condensed Consolidated Balance Sheets	(0.5)	(7.2)
Commodity Option [Member] | Platinum Swaps [Member] | Not Designated as Hedging Instrument [Member] | Fuel Product [Member]
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	0	0
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	0	(0.1)
Net Amounts of Assets Presented in the Condensed Consolidated Balance Sheets	0	(0.1)
Commodity Option [Member] | Natural Gas Collars [Member] | Not Designated as Hedging Instrument [Member] | Specialty Product [Member]
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	0	0.1
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	0	(0.6)
Net Amounts of Assets Presented in the Condensed Consolidated Balance Sheets	0	(0.5)
Cash Flow Hedging [Member] | Commodity Contract [Member] | Crude Oil Swaps [Member] | Designated as Hedging Instrument [Member] | Fuel Product [Member]
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	0	0
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	0	(10)
Net Amounts of Assets Presented in the Condensed Consolidated Balance Sheets	0	(10)
Cash Flow Hedging [Member] | Commodity Contract [Member] | Gasoline Swaps [Member] | Designated as Hedging Instrument [Member] | Fuel Product [Member]
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	0	15.9
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	0	(4.4)
Net Amounts of Assets Presented in the Condensed Consolidated Balance Sheets	$ 0	11.5
Fair Value Hedging [Member] | Interest Rate Contract [Member] | Interest Rate Swap [Member] | Designated as Hedging Instrument [Member] | Not Allocated To A Specific Segment [Member]
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets		2.5
Gross Amounts Offset in the Condensed Consolidated Balance Sheets		0
Net Amounts of Assets Presented in the Condensed Consolidated Balance Sheets	$ 0	$ 2.5

Derivatives - Summary of Gros50

Derivatives - Summary of Gross Fair Values of Derivative Instruments, Presenting the Impact of Offsetting Derivative Liabilities (Details) - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	$ (30.3)	$ (164)
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	12	158.4
Net Amounts of Liabilities Presented in the Condensed Consolidated Balance Sheets	(18.3)	(5.6)
Designated as Hedging Instrument [Member]
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	0	(13.8)
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	0	14.4
Net Amounts of Liabilities Presented in the Condensed Consolidated Balance Sheets	0	0.6
Not Designated as Hedging Instrument [Member]
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	(30.3)	(150.2)
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	12	144
Net Amounts of Liabilities Presented in the Condensed Consolidated Balance Sheets	(18.3)	(6.2)
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	(2.5)	(102.4)
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	2.3	111.2
Net Amounts of Liabilities Presented in the Condensed Consolidated Balance Sheets	(0.2)	8.8
Commodity Contract [Member] | Fuel Product [Member] | Gasoline Swaps [Member] | Not Designated as Hedging Instrument [Member]
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	(7.5)	(1)
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	0	0.4
Net Amounts of Liabilities Presented in the Condensed Consolidated Balance Sheets	(7.5)	(0.6)
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	0	(0.2)
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	2.3	0.2
Net Amounts of Liabilities Presented in the Condensed Consolidated Balance Sheets	2.3	0
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	(2.1)	0
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	1.1	0
Net Amounts of Liabilities Presented in the Condensed Consolidated Balance Sheets	(1)	0
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	(4.1)	0
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	0.9	0
Net Amounts of Liabilities Presented in the Condensed Consolidated Balance Sheets	(3.2)	0
Commodity Contract [Member] | Fuel Product [Member] | Diesel Swaps [Member] | Not Designated as Hedging Instrument [Member]
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	(0.1)	(28.1)
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	0.9	19.1
Net Amounts of Liabilities Presented in the Condensed Consolidated Balance Sheets	0.8	(9)
Commodity Contract [Member] | Fuel Product [Member] | Diesel Crack Spread Swaps [Member] | Not Designated as Hedging Instrument [Member]
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	0	0
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	4	0
Net Amounts of Liabilities Presented in the Condensed Consolidated Balance Sheets	4	0
Commodity Contract [Member] | Fuel Product [Member] | Jet Fuel Swaps [Member] | Not Designated as Hedging Instrument [Member]
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	0	(5.2)
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	0	5.2
Net Amounts of Liabilities Presented in the Condensed Consolidated Balance Sheets	0	0
Commodity Contract [Member] | Fuel Product [Member] | Platinum Swaps [Member] | Not Designated as Hedging Instrument [Member]
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	(0.4)	(0.1)
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	0	0.1
Net Amounts of Liabilities Presented in the Condensed Consolidated Balance Sheets	(0.4)	0
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	(0.3)	0
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	0	0
Net Amounts of Liabilities Presented in the Condensed Consolidated Balance Sheets	(0.3)	0
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	(12.4)	(12.1)
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	0.5	7.2
Net Amounts of Liabilities Presented in the Condensed Consolidated Balance Sheets	(11.9)	(4.9)
Commodity Option [Member] | Specialty Product [Member] | Natural Gas Collars [Member] | Not Designated as Hedging Instrument [Member]
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	(0.9)	(1.1)
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	0	0.6
Net Amounts of Liabilities Presented in the Condensed Consolidated Balance Sheets	(0.9)	(0.5)
Cash Flow Hedging [Member] | Commodity Contract [Member] | Fuel Product [Member] | Crude Oil Swaps [Member] | Designated as Hedging Instrument [Member]
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	0	(13.8)
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	0	10
Net Amounts of Liabilities Presented in the Condensed Consolidated Balance Sheets	0	(3.8)
Cash Flow Hedging [Member] | Commodity Contract [Member] | Fuel Product [Member] | Gasoline Swaps [Member] | Designated as Hedging Instrument [Member]
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	0	0
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	0	4.4
Net Amounts of Liabilities Presented in the Condensed Consolidated Balance Sheets	$ 0	$ 4.4

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		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Income (Loss) on Derivatives (Effective Portion)	$ (1.1)	$ 8.1	$ (6.2)	$ 50.5
Amount of Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) into Net Income (Loss) (Effective Portion)	11.5	1.1	9.8	(2.8)
Amount of Gain (Loss) Recognized in Net Income (Loss) on Derivatives (Ineffective Portion)	0	24.6	0.5	42.7
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 Income (Loss) on Derivatives (Effective Portion)	(2.7)	53.5	(9)	71.2
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 Income (Loss) into Net Income (Loss) (Effective Portion)	(53.2)	13.6	(74.7)	23.1
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	30.3	(0.2)	47.7
Commodity Contract [Member] | Fuel Product [Member] | Gasoline Swaps [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Income (Loss) on Derivatives (Effective Portion)	2.7	(8.2)	3.5	(10)
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 Income (Loss) into Net Income (Loss) (Effective Portion)	19.3	(5.8)	33.3	(11.5)
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	(3.6)	0.7	(4.5)
Commodity Contract [Member] | Fuel Product [Member] | Diesel Swaps [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Income (Loss) on Derivatives (Effective Portion)	(1.4)	(33.4)	(1.3)	(13.4)
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 Income (Loss) into Net Income (Loss) (Effective Portion)	39.8	(4.9)	44.6	(11.1)
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	(1.6)	0	(0.1)
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 Income (Loss) on Derivatives (Effective Portion)	0.3	(3.8)	0.6	2.7
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 Income (Loss) into Net Income (Loss) (Effective Portion)	4	(0.9)	5.4	(2.1)
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	(0.5)	0	(0.4)
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 Income (Loss) on Derivatives (Effective Portion)	0	0	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 Income (Loss) into Net Income (Loss) (Effective Portion)	1.6	(0.9)	1.2	(1.2)
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	$ 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	6 Months Ended
	Jun. 30, 2015	Dec. 31, 2014
Derivative [Line Items]
Total	$ (2.3)	$ 13.7
2015 [Member]
Derivative [Line Items]
Accumulated Other Comprehensive Income (Loss)	(1.1)
2016 [Member]
Derivative [Line Items]
Accumulated Other Comprehensive Income (Loss)	10.8
Derivative gains (losses) on cash flow hedges:
Derivative [Line Items]
Total	$ 9.7	$ 25.8

Derivatives - Schedule of Der53

Derivatives - Schedule of Derivative Instruments (Fair Value Hedges) (Details) - Fair Value Hedging [Member] - Interest Expense [Member] - USD ($) $ in Millions	Jan. 13, 2015	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Derivative [Line Items]
Gain (Loss) on Hedged Item				$ 3		$ 2.5
Interest Rate Swap [Member] | Designated as Hedging Instrument [Member]
Derivative [Line Items]
Gain (Loss) of Derivative		$ 0	$ 1	0	$ (0.6)
Gain (Loss) on Hedged Item	$ 3.3	0	$ (1)	0	$ 0.6
Interest Rate Contract [Member] | Interest Rate Swap [Member] | Designated as Hedging Instrument [Member]
Derivative [Line Items]
Gain (Loss) of Derivative		0		0
Gain (Loss) on Hedged Item		$ 0		$ (1)

Derivatives - Schedule of Der54

Derivatives - Schedule of Derivative Instruments (Not Designated as Hedges) (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Realized Gain (Loss) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Realized gain (loss) on derivative instruments	$ 1.2	$ (2.1)	$ 2.4	$ (3.3)
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)	(13.9)	2.8	(5.6)	4.6
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)	5.1	2.2	(22.7)	13.5
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)	7.7	10.5	(40.6)	14.4
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)	5.2	11.1	55.4	14.5
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	0.6	1	1.2
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)	2.2	(1.8)	1.8	(0.5)
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)	(16.4)	(7.6)	(18.4)	(11.2)
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)	(7.1)	(1.5)	(8.2)	1
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)	1.2	(1.6)	59.2	(1.6)
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)	(3.8)	(5.5)	(67.2)	(2.5)
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	0.9	0
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)	7.4	0	1	0
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)	(3.9)	0	(4.7)	0
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)	(1.7)	0	(3.2)	0
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	(0.1)	1.6	(0.5)
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	0	(1.6)	(0.9)
Diesel Crack Spread Collars [Member] | Fuel Product [Member] | Commodity Option [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	0.6	0	1
Diesel Crack Spread Collars [Member] | Fuel Product [Member] | Commodity Option [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	0	0.4
Platinum 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	0	0
Platinum 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	(0.3)	0
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	0	0	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	0	(0.3)	0
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)	(2.5)	0.4	(4.6)	1.3
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)	3.1	0.4	(0.1)	1.3
Gasoline Crack Spread Collars [Member] | Fuel Product [Member] | Commodity Option [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	0	0
Gasoline Crack Spread Collars [Member] | Fuel Product [Member] | Commodity Option [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	$ (0.5)	$ 0	$ 0.2

Derivatives - Schedule of Der55

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]	Jun. 30, 2015MMBTU$ / MMBtu	Dec. 31, 2014MMBTU$ / MMBtu
Derivative [Line Items]
MMBtu	14,230,000	14,380,000
$/MMBtu	4.07	4.18
First Quarter 2015 [Member]
Derivative [Line Items]
MMBtu | MMBTU		1,770,000
$/MMBtu		4.09
Second Quarter 2015 [Member]
Derivative [Line Items]
MMBtu | MMBTU		1,500,000
$/MMBtu		4.11
Third Quarter 2015 [Member]
Derivative [Line Items]
MMBtu	1,500,000	1,500,000
$/MMBtu	4.11	4.11
Fourth Quarter 2015 [Member]
Derivative [Line Items]
MMBtu	1,900,000	1,900,000
$/MMBtu	4.12	4.12
Calendar Year 2016 [Member]
Derivative [Line Items]
MMBtu	5,880,000	5,880,000
$/MMBtu	4.22	4.22
Calendar Year 2017 [Member]
Derivative [Line Items]
MMBtu	4,950,000	1,830,000
$/MMBtu	3.85	4.28

Derivatives - Schedule of Der56

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]	Jun. 30, 2015MMBTU$ / MMBtu	Dec. 31, 2014MMBTU$ / MMBtu
Derivative [Line Items]
MMBtu | MMBTU	1,040,000	1,520,000
Average Bought Call ($/MMBtu)	4.25	4.25
Average Sold Put ($/MMBtu)	3.86	3.84
First Quarter 2015 [Member]
Derivative [Line Items]
MMBtu | MMBTU		240,000
Average Bought Call ($/MMBtu)		4.25
Average Sold Put ($/MMBtu)		3.79
Second Quarter 2015 [Member]
Derivative [Line Items]
MMBtu | MMBTU		240,000
Average Bought Call ($/MMBtu)		4.25
Average Sold Put ($/MMBtu)		3.79
Third Quarter 2015 [Member]
Derivative [Line Items]
MMBtu | MMBTU	240,000	240,000
Average Bought Call ($/MMBtu)	4.25	4.25
Average Sold Put ($/MMBtu)	3.79	3.79
Fourth Quarter 2015 [Member]
Derivative [Line Items]
MMBtu | MMBTU	200,000	200,000
Average Bought Call ($/MMBtu)	4.25	4.25
Average Sold Put ($/MMBtu)	3.85	3.85
Calendar Year 2016 [Member]
Derivative [Line Items]
MMBtu | MMBTU	600,000	600,000
Average Bought Call ($/MMBtu)	4.25	4.25
Average Sold Put ($/MMBtu)	3.89	3.89

Derivatives - Schedule of Der57

Derivatives - Schedule of Derivative Positions (Natural Gas Swaps - Fuel) (Details) - Jun. 30, 2015 - Commodity Contract [Member] - Fuel Product [Member] - Not Designated as Hedging Instrument [Member] - Natural Gas Swaps [Member]	MMBTU$ / MMBtu
Derivative [Line Items]
MMBtu | MMBTU	1,320,000
$/MMBtu	3.38
Calendar Year 2016 [Member]
Derivative [Line Items]
MMBtu | MMBTU	1,320,000
$/MMBtu	3.38

Derivatives - Schedule of Der58

Derivatives - Schedule of Derivative Positions (Crude Oil Swaps & Basis Swaps) (Details) - Commodity Contract [Member] - Fuel Product [Member]	Jun. 30, 2015bbl$ / bbl	Dec. 31, 2014bbl$ / bbl
Crude Oil Swap Purchased [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative, notional amount	1,860,288	3,510,628
Average Swap ($/Bbl) | $ / bbl	60.66	81.89
Crude Oil Swap Purchased [Member] | Not Designated as Hedging Instrument [Member] | First Quarter 2015 [Member]
Derivative [Line Items]
Derivative, notional amount		1,674,000
Barrels per day, purchased		18,600
Average Swap ($/Bbl) | $ / bbl		89.55
Crude Oil Swap Purchased [Member] | Not Designated as Hedging Instrument [Member] | Second Quarter 2015 [Member]
Derivative [Line Items]
Derivative, notional amount		91,000
Barrels per day, purchased		1,000
Average Swap ($/Bbl) | $ / bbl		89.89
Crude Oil Swap Purchased [Member] | Not Designated as Hedging Instrument [Member] | Third Quarter 2015 [Member]
Derivative [Line Items]
Derivative, notional amount	955,000	386,400
Barrels per day, purchased	10,380	4,200
Average Swap ($/Bbl) | $ / bbl	58.96	69.20
Crude Oil Swap Purchased [Member] | Not Designated as Hedging Instrument [Member] | Fourth Quarter 2015 [Member]
Derivative [Line Items]
Derivative, notional amount	185,000	386,400
Barrels per day, purchased	2,011	4,200
Average Swap ($/Bbl) | $ / bbl	61.48	69.20
Crude Oil Swap Purchased [Member] | Not Designated as Hedging Instrument [Member] | Calendar Year 2016 [Member]
Derivative [Line Items]
Derivative, notional amount	720,288	972,828
Barrels per day, purchased	1,968	2,658
Average Swap ($/Bbl) | $ / bbl	62.71	78.02
Crude Oil Swap Sales [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative, notional amount	120,000	1,674,000
Average Swap ($/Bbl) | $ / bbl	38.75	84.21
Crude Oil Swap Sales [Member] | Not Designated as Hedging Instrument [Member] | First Quarter 2015 [Member]
Derivative [Line Items]
Derivative, notional amount		1,674,000
Barrels per day, sold		18,600
Average Swap ($/Bbl) | $ / bbl		84.21
Crude Oil Swap Sales [Member] | Not Designated as Hedging Instrument [Member] | Third Quarter 2015 [Member]
Derivative [Line Items]
Derivative, notional amount	120,000
Barrels per day, sold	1,304
Average Swap ($/Bbl) | $ / bbl	38.75
Crude Oil Basis Swaps Purchased [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative, notional amount		118,000
Average Differential to NYMEX WTI ($/Bbl) | $ / bbl		(22.40)
Crude Oil Basis Swaps Purchased [Member] | Not Designated as Hedging Instrument [Member] | First Quarter 2015 [Member]
Derivative [Line Items]
Derivative, notional amount		118,000
Barrels per day, purchased		2,000
Average Differential to NYMEX WTI ($/Bbl) | $ / bbl		(22.40)
Cash Flow Hedging [Member] | Crude Oil Swap Purchased [Member] | Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative, notional amount		315,000
Average Swap ($/Bbl) | $ / bbl		97.71
Cash Flow Hedging [Member] | Crude Oil Swap Purchased [Member] | Designated as Hedging Instrument [Member] | First Quarter 2015 [Member]
Derivative [Line Items]
Derivative, notional amount		315,000
Barrels per day, purchased		3,500
Average Swap ($/Bbl) | $ / bbl		97.71

Derivatives - Schedule of Der59

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	Jun. 30, 2015	Dec. 31, 2014
Derivative [Line Items]
Derivative, notional amount	1,100,000	368,000
Fixed Percentage of NYMEX WTI (Average % of WTI/Bbl)	74.30%	73.00%
Third Quarter 2015 [Member]
Derivative [Line Items]
Derivative, notional amount	184,000	184,000
Barrels per day, purchased	2,000	2,000
Fixed Percentage of NYMEX WTI (Average % of WTI/Bbl)	73.00%	73.00%
Fourth Quarter 2015 [Member]
Derivative [Line Items]
Derivative, notional amount	184,000	184,000
Barrels per day, purchased	2,000	2,000
Fixed Percentage of NYMEX WTI (Average % of WTI/Bbl)	73.00%	73.00%
Calendar Year 2016 [Member]
Derivative [Line Items]
Derivative, notional amount	732,000
Barrels per day, purchased	2,000
Fixed Percentage of NYMEX WTI (Average % of WTI/Bbl)	75.00%

Derivatives - Schedule of Der60

Derivatives - Schedule of Derivative Positions (Crude Oil Options) (Details) - Jun. 30, 2015 - Not Designated as Hedging Instrument [Member] - Commodity Option [Member] - Fuel Product [Member]	bbl$ / bbl
Crude Oil Options Sold [Member]
Derivative [Line Items]
Derivative, notional amount	1,020,000
Average Sold Call ($/Bbl) | $ / bbl	67.02
Crude Oil Options Bought [Member]
Derivative [Line Items]
Derivative, notional amount	600,000
Average Bought Put ($/Bbl) | $ / bbl	54.17
Third Quarter 2015 [Member] | Crude Oil Options Sold [Member]
Derivative [Line Items]
Derivative, notional amount	120,000
Barrels per day, sold	1,304
Average Sold Call ($/Bbl) | $ / bbl	64.71
Third Quarter 2015 [Member] | Crude Oil Options Bought [Member]
Derivative [Line Items]
Derivative, notional amount	200,000
Barrels per day, purchased	2,174
Third Quarter 2015 [Member] | Crude Oil Options [Member]
Derivative [Line Items]
Average Bought Put ($/Bbl) | $ / bbl	53.50
Fourth Quarter 2015 [Member] | Crude Oil Options Sold [Member]
Derivative [Line Items]
Derivative, notional amount	800,000
Barrels per day, sold	8,696
Average Sold Call ($/Bbl) | $ / bbl	67.63
Fourth Quarter 2015 [Member] | Crude Oil Options Bought [Member]
Derivative [Line Items]
Derivative, notional amount	300,000
Barrels per day, purchased	3,261
Average Bought Put ($/Bbl) | $ / bbl	54.33
Calendar Year 2016 [Member] | Crude Oil Options Sold [Member]
Derivative [Line Items]
Derivative, notional amount	100,000
Barrels per day, sold	273
Average Sold Call ($/Bbl) | $ / bbl	65
Calendar Year 2016 [Member] | Crude Oil Options Bought [Member]
Derivative [Line Items]
Derivative, notional amount	100,000
Barrels per day, purchased	273
Average Bought Put ($/Bbl) | $ / bbl	55

Derivatives - Schedule of Der61

Derivatives - Schedule of Derivative Positions (Diesel Swaps) (Details) - Commodity Contract [Member] - Fuel Product [Member] - Not Designated as Hedging Instrument [Member]	Jun. 30, 2015bbl$ / bbl	Dec. 31, 2014bbl$ / bbl
Diesel Swaps Sold [Member]
Derivative [Line Items]
Derivative, notional amount	733,000	3,099,000
Average Swap ($/Bbl) | $ / bbl	82.22	108.38
Diesel Swaps Sold [Member] | First Quarter 2015 [Member]
Derivative [Line Items]
Derivative, notional amount		1,449,000
Barrels per day, sold		16,100
Average Swap ($/Bbl) | $ / bbl		116.27
Diesel Swaps Sold [Member] | Second Quarter 2015 [Member]
Derivative [Line Items]
Derivative, notional amount		91,000
Barrels per day, sold		1,000
Average Swap ($/Bbl) | $ / bbl		117.92
Diesel Swaps Sold [Member] | Third Quarter 2015 [Member]
Derivative [Line Items]
Derivative, notional amount	92,000	322,000
Barrels per day, sold	1,000	3,500
Average Swap ($/Bbl) | $ / bbl	82.07	95.04
Diesel Swaps Sold [Member] | Fourth Quarter 2015 [Member]
Derivative [Line Items]
Derivative, notional amount	92,000	322,000
Barrels per day, sold	1,000	3,500
Average Swap ($/Bbl) | $ / bbl	82.07	95.04
Diesel Swaps Sold [Member] | Calendar Year 2016 [Member]
Derivative [Line Items]
Derivative, notional amount	549,000	915,000
Barrels per day, sold	1,500	2,500
Average Swap ($/Bbl) | $ / bbl	82.28	104.32
Diesel Swaps Purchased [Member]
Derivative [Line Items]
Derivative, notional amount		1,449,000
Average Swap ($/Bbl) | $ / bbl		105.78
Diesel Swaps Purchased [Member] | First Quarter 2015 [Member]
Derivative [Line Items]
Derivative, notional amount		1,449,000
Barrels per day, purchased		16,100
Average Swap ($/Bbl) | $ / bbl		105.78

Derivatives - Schedule of Der62

Derivatives - Schedule of Derivative Positions (Diesel Percent Basis Crack Spread Swaps) (Details) - Fuel Product [Member] - Commodity Option [Member] - Not Designated as Hedging Instrument [Member] - Diesel Percent Basis Crack Spread Swaps Sold [Member] - bbl	Jun. 30, 2015	Dec. 31, 2014
Derivative [Line Items]
Derivative, notional amount	2,288,000	2,475,000
Fixed Percentage of NYMEX WTI (Average % of WTI/Bbl)	31.80%	32.20%
Third Quarter 2015 [Member]
Derivative [Line Items]
Derivative, notional amount	46,000	414,000
Barrels per day, sold	500	4,500
Fixed Percentage of NYMEX WTI (Average % of WTI/Bbl)	32.50%	33.20%
Fourth Quarter 2015 [Member]
Derivative [Line Items]
Derivative, notional amount	46,000	414,000
Barrels per day, sold	500	4,500
Fixed Percentage of NYMEX WTI (Average % of WTI/Bbl)	32.50%	33.20%
Calendar Year 2016 [Member]
Derivative [Line Items]
Derivative, notional amount	2,196,000	1,647,000
Barrels per day, sold	6,000	4,500
Fixed Percentage of NYMEX WTI (Average % of WTI/Bbl)	31.80%	31.70%

Derivatives Derivatives - Sched

Derivatives Derivatives - Schedule of Derivative Positions (Diesel Crack Spread Swaps) (Details) - Commodity Contract [Member] - Designated as Hedging Instrument [Member] - Fuel Product [Member] - Cash Flow Hedging [Member]	Jun. 30, 2015bbl$ / bbl	Dec. 31, 2014bbl$ / bbl
Diesel Crack Spread Swaps [Member]
Derivative [Line Items]
Derivative, notional amount	1,196,000
Average Swap ($/Bbl) | $ / bbl	20.38
Gasoline Swaps Sold [Member]
Derivative [Line Items]
Derivative, notional amount	956,000	315,000
Average Swap ($/Bbl) | $ / bbl	74.21	109.68
Fourth Quarter 2015 [Member] | Diesel Crack Spread Swaps [Member]
Derivative [Line Items]
Derivative, notional amount	598,000
Barrels per day, sold	6,500
Average Swap ($/Bbl) | $ / bbl	20.38
Fourth Quarter 2015 [Member] | Gasoline Swaps Sold [Member]
Derivative [Line Items]
Derivative, notional amount	93,000
Barrels per day, sold	1,011
Average Swap ($/Bbl) | $ / bbl	70.53
Third Quarter 2015 [Member] | Diesel Crack Spread Swaps [Member]
Derivative [Line Items]
Derivative, notional amount	598,000
Barrels per day, sold	6,500
Average Swap ($/Bbl) | $ / bbl	20.38
Third Quarter 2015 [Member] | Gasoline Swaps Sold [Member]
Derivative [Line Items]
Derivative, notional amount	863,000
Barrels per day, sold	9,380
Average Swap ($/Bbl) | $ / bbl	74.60

Derivatives - Schedule of Der64

Derivatives - Schedule of Derivative Positions (Jet Fuel Swaps) (Details) - Dec. 31, 2014 - Commodity Contract [Member] - Fuel Product [Member]	bbl$ / bbl
Jet Fuel Swaps Purchased [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative, notional amount	180,000
Average Swap ($/Bbl) | $ / bbl	100.91
Jet Fuel Swaps Purchased [Member] | Not Designated as Hedging Instrument [Member] | First Quarter 2015 [Member]
Derivative [Line Items]
Derivative, notional amount	180,000
Barrels per day, purchased	2,000
Average Swap ($/Bbl) | $ / bbl	100.91
Cash Flow Hedging [Member] | Jet Fuel Swaps Sold [Member] | Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative, notional amount	180,000
Average Swap ($/Bbl) | $ / bbl	115.65
Cash Flow Hedging [Member] | Jet Fuel Swaps Sold [Member] | Designated as Hedging Instrument [Member] | First Quarter 2015 [Member]
Derivative [Line Items]
Derivative, notional amount	180,000
Barrels per day, sold	2,000
Average Swap ($/Bbl) | $ / bbl	115.65

Derivatives - Schedule of Der65

Derivatives - Schedule of Derivative Positions (Gasoline Swaps) (Details) - Commodity Contract [Member] - Fuel Product [Member]	Jun. 30, 2015bbl$ / bbl	Dec. 31, 2014bbl$ / bbl
Gasoline Swaps Sold [Member] | Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member]
Derivative [Line Items]
Derivative, notional amount	956,000	315,000
Average Swap ($/Bbl) | $ / bbl	74.21	109.68
Gasoline Swaps Sold [Member] | Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | First Quarter 2015 [Member]
Derivative [Line Items]
Derivative, notional amount		315,000
Barrels per day, sold		3,500
Average Swap ($/Bbl) | $ / bbl		109.68
Gasoline Swaps Sold [Member] | Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | Third Quarter 2015 [Member]
Derivative [Line Items]
Derivative, notional amount	863,000
Barrels per day, sold	9,380
Average Swap ($/Bbl) | $ / bbl	74.60
Gasoline Swaps Sold [Member] | Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | Fourth Quarter 2015 [Member]
Derivative [Line Items]
Derivative, notional amount	93,000
Barrels per day, sold	1,011
Average Swap ($/Bbl) | $ / bbl	70.53
Gasoline Swaps Sold [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative, notional amount		45,000
Average Swap ($/Bbl) | $ / bbl		111.72
Gasoline Swaps Sold [Member] | Not Designated as Hedging Instrument [Member] | First Quarter 2015 [Member]
Derivative [Line Items]
Derivative, notional amount		45,000
Barrels per day, sold		500
Average Swap ($/Bbl) | $ / bbl		111.72
Gasoline Swaps Purchased [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative, notional amount		45,000
Average Swap ($/Bbl) | $ / bbl		78.12
Gasoline Swaps Purchased [Member] | Not Designated as Hedging Instrument [Member] | First Quarter 2015 [Member]
Derivative [Line Items]
Derivative, notional amount		45,000
Barrels per day, purchased		500
Average Swap ($/Bbl) | $ / bbl		78.12

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]	Jun. 30, 2015bbl$ / bbl	Dec. 31, 2014bbl
Derivative [Line Items]
Derivative, notional amount	1,196,500
Average Swap ($/Bbl) | $ / bbl	11.10
Third Quarter 2015 [Member]
Derivative [Line Items]
Derivative, notional amount		491,000
Barrels per day, sold	5,337
Average Swap ($/Bbl) | $ / bbl	15.65
Fourth Quarter 2015 [Member]
Derivative [Line Items]
Derivative, notional amount		705,500
Barrels per day, sold	7,668
Average Swap ($/Bbl) | $ / bbl	7.93

Derivatives - Narrative (Detail

Derivatives - Narrative (Details)	Jan. 13, 2015USD ($)	Jun. 30, 2015USD ($)	Jun. 30, 2014USD ($)	Jun. 30, 2015USD ($)	Jun. 30, 2014USD ($)	Dec. 31, 2014USD ($)
Derivative [Line Items]
Counterparties in which derivatives held were net assets				1		5
Collateral		$ 0		$ 0		$ 0
Accumulated other comprehensive income (loss)		(2,300,000)		(2,300,000)		13,700,000
Net gains on derivative instruments expected to reclassifying from AOCI to earnings during next twelve months				4,600,000
Notional amount	$ 200,000,000
Derivative gains (losses) on cash flow hedges:
Derivative [Line Items]
Accumulated other comprehensive income (loss)		9,700,000		9,700,000		25,800,000
Fair Value Hedging [Member] | Interest Expense [Member]
Derivative [Line Items]
Gain (Loss) on Hedged Item				3,000,000		$ 2,500,000
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	$ 0	$ (1,000,000)	$ 0	$ 600,000
Commodity Contract [Member] | 2015 [Member] | Fuel Product [Member] | Not Designated as Hedging Instrument [Member] | Platinum Swaps [Member]
Derivative [Line Items]
Derivative, notional amount		1,900		1,900		1,900

Fair Value Measurements - Narra

Fair Value Measurements - Narrative (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2015	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Reduction in net derivative liability	$ 0.3	$ (0.1)
Increase in net derivative asset		$ 2
Gain on sale of RINs	35
Loss on RINs Obligation	$ 32.7
Date goodwill impairment is reviewed, annually	Oct. 1, 2014

Fair Value Measurements - Summa

Fair Value Measurements - Summary of Recurring Assets and Liabilities Measured at Fair Value (Details) - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
Derivative assets:
Total derivative assets	$ 1.2	$ 23.2
Derivative liabilities:
Total derivative liabilities	(18.3)	(5.6)
Fair Value, Measurements, Recurring [Member]
Derivative assets:
Total derivative assets	1.2	23.2
Pension plan investments	48.6	49.6
Total recurring assets at fair value	49.8	72.8
Derivative liabilities:
Total derivative liabilities	(18.3)	(5.6)
RINs Obligation	(41.5)	(16.3)
Liability Awards	(6.4)	(4.7)
Total recurring liabilities at fair value	(66.2)	(26.6)
Fair Value, Measurements, Recurring [Member] | Level 1 [Member]
Derivative assets:
Total derivative assets	0	0
Pension plan investments	0.5	0.2
Total recurring assets at fair value	0.5	0.2
Derivative liabilities:
Total derivative liabilities	0	0
RINs Obligation	0	0
Liability Awards	(6.4)	(4.7)
Total recurring liabilities at fair value	(6.4)	(4.7)
Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Derivative assets:
Total derivative assets	0	0
Pension plan investments	48.1	49.4
Total recurring assets at fair value	48.1	49.4
Derivative liabilities:
Total derivative liabilities	0	0
RINs Obligation	(41.5)	(16.3)
Liability Awards	0	0
Total recurring liabilities at fair value	(41.5)	(16.3)
Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Derivative assets:
Total derivative assets	1.2	23.2
Pension plan investments	0	0
Total recurring assets at fair value	1.2	23.2
Derivative liabilities:
Total derivative liabilities	(18.3)	(5.6)
RINs Obligation	0	0
Liability Awards	0	0
Total recurring liabilities at fair value	(18.3)	(5.6)
Crude Oil Swaps [Member] | Fair Value, Measurements, Recurring [Member]
Derivative assets:
Total derivative assets	(0.6)	(89.8)
Derivative liabilities:
Total derivative liabilities	(0.2)	5
Crude Oil Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 1 [Member]
Derivative assets:
Total derivative assets	0	0
Derivative liabilities:
Total derivative liabilities	0	0
Crude Oil Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Derivative assets:
Total derivative assets	0	0
Derivative liabilities:
Total derivative liabilities	0	0
Crude Oil Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Derivative assets:
Total derivative assets	(0.6)	(89.8)
Derivative liabilities:
Total derivative liabilities	(0.2)	5
Crude Oil Basis Swaps [Member] | Fair Value, Measurements, Recurring [Member]
Derivative assets:
Total derivative assets	0	0.8
Crude Oil Basis Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 1 [Member]
Derivative assets:
Total derivative assets	0	0
Crude Oil Basis Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Derivative assets:
Total derivative assets	0	0
Crude Oil Basis Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Derivative assets:
Total derivative assets	0	0.8
Crude Oil Percent Basis Swaps [Member] | Fair Value, Measurements, Recurring [Member]
Derivative assets:
Total derivative assets	0	(0.2)
Derivative liabilities:
Total derivative liabilities	2.3	0
Crude Oil Percent Basis Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 1 [Member]
Derivative assets:
Total derivative assets	0	0
Derivative liabilities:
Total derivative liabilities	0	0
Crude Oil Percent Basis Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Derivative assets:
Total derivative assets	0	0
Derivative liabilities:
Total derivative liabilities	0	0
Crude Oil Percent Basis Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Derivative assets:
Total derivative assets	0	(0.2)
Derivative liabilities:
Total derivative liabilities	2.3	0
Gasoline Swaps [Member] | Fair Value, Measurements, Recurring [Member]
Derivative assets:
Total derivative assets	0	13.5
Derivative liabilities:
Total derivative liabilities	(7.5)	3.8
Gasoline Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 1 [Member]
Derivative assets:
Total derivative assets	0	0
Derivative liabilities:
Total derivative liabilities	0	0
Gasoline Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Derivative assets:
Total derivative assets	0	0
Derivative liabilities:
Total derivative liabilities	0	0
Gasoline Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Derivative assets:
Total derivative assets	0	13.5
Derivative liabilities:
Total derivative liabilities	(7.5)	3.8
Gasoline Crack Spread Swaps [Member] | Fair Value, Measurements, Recurring [Member]
Derivative liabilities:
Total derivative liabilities	(3.2)	0
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	(3.2)	0
Diesel Swaps [Member] | Fair Value, Measurements, Recurring [Member]
Derivative assets:
Total derivative assets	0.7	97
Derivative liabilities:
Total derivative liabilities	0.8	(9)
Diesel Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 1 [Member]
Derivative assets:
Total derivative assets	0	0
Derivative liabilities:
Total derivative liabilities	0	0
Diesel Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Derivative assets:
Total derivative assets	0	0
Derivative liabilities:
Total derivative liabilities	0	0
Diesel Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Derivative assets:
Total derivative assets	0.7	97
Derivative liabilities:
Total derivative liabilities	0.8	(9)
Diesel Crack Spread Swaps [Member] | Fair Value, Measurements, Recurring [Member]
Derivative assets:
Total derivative assets	1.6	4.5
Derivative liabilities:
Total derivative liabilities	4	0
Diesel Crack Spread Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 1 [Member]
Derivative assets:
Total derivative assets	0	0
Derivative liabilities:
Total derivative liabilities	0	0
Diesel Crack Spread Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Derivative assets:
Total derivative assets	0	0
Derivative liabilities:
Total derivative liabilities	0	0
Diesel Crack Spread Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Derivative assets:
Total derivative assets	1.6	4.5
Derivative liabilities:
Total derivative liabilities	4	0
Jet Fuel Swaps [Member] | Fair Value, Measurements, Recurring [Member]
Derivative assets:
Total derivative assets	0	2.7
Jet Fuel Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 1 [Member]
Derivative assets:
Total derivative assets	0	0
Jet Fuel Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Derivative assets:
Total derivative assets	0	0
Jet Fuel Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Derivative assets:
Total derivative assets	0	2.7
Natural Gas Swaps [Member] | Fair Value, Measurements, Recurring [Member]
Derivative assets:
Total derivative assets	(0.5)	(7.2)
Derivative liabilities:
Total derivative liabilities	(12.2)	(4.9)
Natural Gas Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 1 [Member]
Derivative assets:
Total derivative assets	0	0
Derivative liabilities:
Total derivative liabilities	0	0
Natural Gas Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Derivative assets:
Total derivative assets	0	0
Derivative liabilities:
Total derivative liabilities	0	0
Natural Gas Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Derivative assets:
Total derivative assets	(0.5)	(7.2)
Derivative liabilities:
Total derivative liabilities	(12.2)	(4.9)
Natural Gas Collars [Member] | Fair Value, Measurements, Recurring [Member]
Derivative assets:
Total derivative assets	0	(0.5)
Derivative liabilities:
Total derivative liabilities	(0.9)	(0.5)
Natural Gas Collars [Member] | Fair Value, Measurements, Recurring [Member] | Level 1 [Member]
Derivative assets:
Total derivative assets	0	0
Derivative liabilities:
Total derivative liabilities	0	0
Natural Gas Collars [Member] | Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Derivative assets:
Total derivative assets	0	0
Derivative liabilities:
Total derivative liabilities	0	0
Natural Gas Collars [Member] | Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Derivative assets:
Total derivative assets	0	(0.5)
Derivative liabilities:
Total derivative liabilities	(0.9)	(0.5)
Platinum Swaps [Member] | Fair Value, Measurements, Recurring [Member]
Derivative assets:
Total derivative assets	0	(0.1)
Derivative liabilities:
Total derivative liabilities	(0.4)	0
Platinum Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 1 [Member]
Derivative assets:
Total derivative assets	0	0
Derivative liabilities:
Total derivative liabilities	0	0
Platinum Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Derivative assets:
Total derivative assets	0	0
Derivative liabilities:
Total derivative liabilities	0	0
Platinum Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Derivative assets:
Total derivative assets	0	(0.1)
Derivative liabilities:
Total derivative liabilities	(0.4)	0
Interest Rate Swaps [Member] | Fair Value, Measurements, Recurring [Member]
Derivative assets:
Total derivative assets	0	2.5
Interest Rate Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 1 [Member]
Derivative assets:
Total derivative assets	0	0
Interest Rate Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Derivative assets:
Total derivative assets	0	0
Interest Rate Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Derivative assets:
Total derivative assets	0	2.5
Crude Oil Options [Member] | Fair Value, Measurements, Recurring [Member]
Derivative liabilities:
Total derivative liabilities	(1)	0
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	$ (1)	$ 0

Fair Value Measurements - Sum70

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		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Summary of net changes in fair value of the company's level 3 financial assets and liabilities
Realized (gain) loss on derivative instruments	$ (14)	$ 6	$ (5.1)	$ 12.6
Interest expense, net	(27.4)	(28.7)	(54.4)	(54.9)
Change in fair value of cash flow hedges	$ (1.1)	8.1	(6.2)	50.5
Level 3 [Member]
Summary of net changes in fair value of the company's level 3 financial assets and liabilities
Fair value at January 1,			17.6	(54.8)
Realized (gain) loss on derivative instruments			5.1	(12.6)
Unrealized gain (loss) on derivative instruments			(22.7)	48.2
Interest expense, net			(0.3)	(1.9)
Change in fair value of cash flow hedges			(6.2)	50.5
Settlements			(10.6)	12.9
Transfers in (out) of Level 3			0	0
Fair value at June 30,		$ 42.3		42.3
Total gain (loss) included in net income (loss) attributable to changes in unrealized gain (loss) relating to financial assets and liabilities held as of June 30,			$ (22.7)	$ 48.2

Fair Value Measurements - Sum71

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	Jun. 30, 2015	Dec. 31, 2014
Fair Value [Member] | Level 1 [Member]
Financial Instrument:
Senior notes	$ 1,252.1	$ 630
Fair Value [Member] | Level 2 [Member]
Financial Instrument:
Senior notes	333.9	803.3
Fair Value [Member] | Revolving Credit Facility [Member] | Level 3 [Member]
Financial Instrument:
Revolving credit facility	103.1	150.8
Carrying Value [Member] | Level 1 [Member]
Financial Instrument:
Senior notes	1,248.5	619.1
Carrying Value [Member] | Level 2 [Member]
Financial Instrument:
Senior notes	322.6	900
Carrying Value [Member] | Revolving Credit Facility [Member] | Level 3 [Member]
Financial Instrument:
Revolving credit facility	103.1	150.8
Carrying Value [Member] | Capital Lease Obligations [Member] | Level 3 [Member]
Financial Instrument:
Capital lease and other obligations	$ 43.4	$ 43.6

Partners' Capital - Narrative (

Partners' Capital - Narrative (Details) - USD ($)	Mar. 13, 2015	Feb. 19, 2015	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Partners' Capital [Abstract]
Common units sold (in shares)	6,000,000				307,985
Offering share price (in USD per share)	$ 26.75
Proceeds from sale of common units, net	$ 153,900,000	$ 7,600,000	$ 0	$ 0	$ 161,500,000	$ 0
Underwriting discounts	6,400,000		100,000		100,000
General partner contribution amount	$ 3,300,000		200,000		200,000
Equity Placement Agreement aggregate offering price up to			300,000,000		300,000,000
Distributions to partners			57,300,000	52,500,000	110,000,000	105,100,000
General partner’s incentive distribution rights			$ 4,200,000	$ 3,900,000	$ 8,400,000	$ 7,700,000

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		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Components of net periodic pension and other post retirement benefits cost
Service cost	$ 0.2	$ 0.1	$ 0.3	$ 0.2
Interest cost	0.6	0.6	1.3	1.3
Expected return on assets	(0.9)	(0.7)	(1.7)	(1.5)
Amortization of net loss	0.2	0	0.4	0.2
Net periodic benefit cost	$ 0.1	$ 0	$ 0.3	$ 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	Jun. 30, 2015	Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	$ 48.6	$ 49.6
Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	0.5	0.2
Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	48.1	49.4
Cash and Cash Equivalents [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	0.5	0.2
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	10
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	9.5	9.4
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	$ 28.9	$ 30

Employee Benefit Plans - Narrat

Employee Benefit Plans - Narrative (Details)	6 Months Ended
	Jun. 30, 2015
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 Comprehensi76

Accumulated Other Comprehensive Income - Summary of Reclassification Adjustments out of Accumulated Other Comprehensive Income (Loss) (Details) - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total		$ (12.5)	$ 7.1	$ (16)	$ 53.8
Amount Reclassified From Accumulated Other Comprehensive Income [Member] | Derivative gains (losses) on cash flow hedges:
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Sales		63.1	(11.6)	83.3	(24.7)
Cost of sales		(51.6)	12.7	(73.5)	21.9
Total		11.5	1.1	9.8	(2.8)
Amount Reclassified From Accumulated Other Comprehensive Income [Member] | Amortization of defined benefit pension and postretirement health benefit plans:
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total		(0.2)	0	(0.4)	(0.2)
Pension Plan [Member] | Amount Reclassified From Accumulated Other Comprehensive Income [Member] | Amortization of defined benefit pension and postretirement health benefit plans:
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Amortization of net loss	[1]	$ (0.2)	$ 0	$ (0.4)	$ (0.2)
[1]	This accumulated other comprehensive income (loss) component is included in the computation of net periodic pension cost. See Note 11 for additional details.

Earnings Per Unit - Summary of

Earnings Per Unit - Summary of Computation of Basic and Diluted Earnings Per Limited Partner Unit (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended				6 Months Ended
	Jun. 30, 2015		Jun. 30, 2014		Jun. 30, 2015	Jun. 30, 2014
Numerator for basic and diluted earnings per limited partner unit:
Net income (loss)	$ 2.5		$ (8.3)		$ 26.3	$ (58.1)
General partner’s interest in net income (loss)	0		(0.2)		0.5	(1.2)
General partner’s incentive distribution rights	4.2		3.9		8.4	7.7
Non-vested share based payments	0		0		0	0
Net income (loss) available to limited partners	$ (1.7)		$ (12)		$ 17.4	$ (64.6)
Denominator for basic and diluted earnings per limited partner unit:
Basic weighted average limited partner units outstanding (in shares)	76,092,517		69,604,669		73,675,251	69,614,055
Participating securities — phantom units (in shares)	0		0		54,938	0
Diluted weighted average limited partner units outstanding (in shares)	76,092,517	[1]	69,604,669	[1]	73,730,189	69,614,055	[1]
Limited partners' interest basic and diluted net income (loss) per unit (in USD per share)	$ (0.02)		$ (0.17)		$ 0.23	$ (0.93)
Dilutive phantom units excluded (in shares)	100,000		200,000			100,000
[1]	Total diluted weighted average limited partner units outstanding excludes 0.1 million of dilutive phantom units for the three months ended June 30, 2015. Total diluted weighted average limited partner units outstanding excludes 0.2 million and 0.1 million of dilutive phantom units for the three and six months ended June 30, 2014, respectively.

Segments and Related Informat78

Segments and Related Information - Schedule of Reportable Segment Information (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Sales:
Total sales	$ 1,156.2	$ 1,434.9	$ 2,174.8	$ 2,775.9
Adjusted EBITDA	95	39.3	219.9	122
Reconciling items to net income:
Depreciation and amortization	42.6	41.5	84.1	77.5
Realized gain on derivatives, not reflected in net income (loss)	(12.6)	1.9	(6.5)	3.4
Unrealized (gain) loss on derivatives	(5.2)	(23.6)	22.7	(48.2)
Interest expense	27.4	28.7	54.4	54.9
Debt extinguishment costs	46.6	0	46.6	89.6
Non-cash equity based compensation and other non-cash items	2.8	1	6.2	4.6
Income tax (benefit) expense	(9.1)	(1.9)	(13.9)	(1.7)
Net income (loss)	2.5	(8.3)	26.3	(58.1)
External Customers [Member]
Sales:
Total sales	1,156.2	1,434.9	2,174.8	2,775.9
Intersegment Sales [Member]
Sales:
Total sales	0	0	0	0
Operating Segments [Member] | Specialty Products [Member]
Sales:
Total sales	372.3	431.6	735.2	881.6
Adjusted EBITDA	59.1	34.3	120.7	92
Reconciling items to net income:
Depreciation and amortization	16.7	16.7	32.6	33.4
Realized gain on derivatives, not reflected in net income (loss)	(1.6)	0.9	(1.2)	1.2
Operating Segments [Member] | Specialty Products [Member] | External Customers [Member]
Sales:
Total sales	370.6	424.4	732.2	874.4
Operating Segments [Member] | Specialty Products [Member] | Intersegment Sales [Member]
Sales:
Total sales	1.7	7.2	3	7.2
Operating Segments [Member] | Fuel Products [Member]
Sales:
Total sales	727.2	928.6	1,308.4	1,836.8
Adjusted EBITDA	50.1	(3.1)	117.5	21.9
Reconciling items to net income:
Depreciation and amortization	20.2	20.3	40.2	39.6
Realized gain on derivatives, not reflected in net income (loss)	(11)	1	(5.3)	2.2
Operating Segments [Member] | Fuel Products [Member] | External Customers [Member]
Sales:
Total sales	715.1	900.7	1,283.4	1,791.7
Operating Segments [Member] | Fuel Products [Member] | Intersegment Sales [Member]
Sales:
Total sales	12.1	27.9	25	45.1
Operating Segments [Member] | Oilfield Services [Member]
Sales:
Total sales	70.5	109.8	159.2	109.8
Adjusted EBITDA	(14.2)	8.1	(18.3)	8.1
Reconciling items to net income:
Depreciation and amortization	5.7	4.5	11.3	4.5
Realized gain on derivatives, not reflected in net income (loss)	0	0	0	0
Operating Segments [Member] | Oilfield Services [Member] | External Customers [Member]
Sales:
Total sales	70.5	109.8	159.2	109.8
Operating Segments [Member] | Oilfield Services [Member] | Intersegment Sales [Member]
Sales:
Total sales	0	0	0	0
Operating Segments [Member] | Combined Segments [Member]
Sales:
Total sales	1,170	1,470	2,202.8	2,828.2
Adjusted EBITDA	95	39.3	219.9	122
Reconciling items to net income:
Depreciation and amortization	42.6	41.5	84.1	77.5
Realized gain on derivatives, not reflected in net income (loss)	(12.6)	1.9	(6.5)	3.4
Operating Segments [Member] | Combined Segments [Member] | External Customers [Member]
Sales:
Total sales	1,156.2	1,434.9	2,174.8	2,775.9
Operating Segments [Member] | Combined Segments [Member] | Intersegment Sales [Member]
Sales:
Total sales	13.8	35.1	28	52.3
Eliminations [Member]
Sales:
Total sales	(13.8)	(35.1)	(28)	(52.3)
Adjusted EBITDA	0	0	0	0
Reconciling items to net income:
Depreciation and amortization	0	0	0	0
Realized gain on derivatives, not reflected in net income (loss)	0	0	0	0
Eliminations [Member] | External Customers [Member]
Sales:
Total sales	0	0	0	0
Eliminations [Member] | Intersegment Sales [Member]
Sales:
Total sales	$ (13.8)	$ (35.1)	$ (28)	$ (52.3)

Segments and Related Informat79

Segments and Related Information - Schedule of Major Product Category Sales (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Major product category sales
Sales	$ 1,156.2	$ 1,434.9	$ 2,174.8	$ 2,775.9
Sales, percentage	49.50%	44.00%	48.80%	46.00%
Product Concentration Risk [Member]
Major product category sales
Sales	$ 1,156.2	$ 1,434.9	$ 2,174.8	$ 2,775.9
Sales, percentage	100.00%	100.00%	100.00%	100.00%
Product Concentration Risk [Member] | Specialty Products [Member]
Major product category sales
Sales	$ 370.6	$ 424.4	$ 732.2	$ 874.4
Sales, percentage	32.10%	29.60%	33.80%	31.50%
Product Concentration Risk [Member] | Specialty Products [Member] | Lubricating Oils [Member]
Major product category sales
Sales	$ 158.1	$ 184.4	$ 307.9	$ 382.1
Sales, percentage	13.70%	12.90%	14.20%	13.80%
Product Concentration Risk [Member] | Specialty Products [Member] | Solvents [Member]
Major product category sales
Sales	$ 81.6	$ 120.6	$ 167.8	$ 252
Sales, percentage	7.10%	8.40%	7.70%	9.10%
Product Concentration Risk [Member] | Specialty Products [Member] | Waxes [Member]
Major product category sales
Sales	$ 33.9	$ 30.9	$ 72.9	$ 66.3
Sales, percentage	2.90%	2.20%	3.40%	2.40%
Product Concentration Risk [Member] | Specialty Products [Member] | Packaged and Synthetic Specialty Products [Member]
Major product category sales
Sales	$ 88.4	$ 79.8	$ 168.9	$ 156.2
Sales, percentage	7.60%	5.60%	7.80%	5.60%
Product Concentration Risk [Member] | Specialty Products [Member] | Other [Member]
Major product category sales
Sales	$ 8.6	$ 8.7	$ 14.7	$ 17.8
Sales, percentage	0.80%	0.50%	0.70%	0.60%
Product Concentration Risk [Member] | Fuel Products [Member]
Major product category sales
Sales	$ 715.1	$ 900.7	$ 1,283.4	$ 1,791.7
Sales, percentage	61.90%	62.80%	58.90%	64.50%
Product Concentration Risk [Member] | Fuel Products [Member] | Gasoline [Member]
Major product category sales
Sales	$ 302.6	$ 358.3	$ 548.9	$ 717.9
Sales, percentage	26.20%	25.00%	25.10%	25.90%
Product Concentration Risk [Member] | Fuel Products [Member] | Diesel [Member]
Major product category sales
Sales	$ 251	$ 268	$ 464.9	$ 585.4
Sales, percentage	21.70%	18.70%	21.40%	21.10%
Product Concentration Risk [Member] | Fuel Products [Member] | Jet fuel [Member]
Major product category sales
Sales	$ 37.9	$ 42.1	$ 76.1	$ 86.1
Sales, percentage	3.30%	2.90%	3.50%	3.10%
Product Concentration Risk [Member] | Fuel Products [Member] | Asphalt, Heavy Fuel Oils and Other [Member]
Major product category sales
Sales	$ 123.6	$ 232.3	$ 193.5	$ 402.3
Sales, percentage	10.70%	16.20%	8.90%	14.40%
Product Concentration Risk [Member] | Oilfield Services [Member]
Major product category sales
Sales	$ 70.5	$ 109.8	$ 159.2	$ 109.8
Sales, percentage	6.00%	7.60%	7.30%	4.00%

Segments and Related Informat80

Segments and Related Information - Narrative (Details)	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Segment Reporting [Abstract]
Number of customers representing 10% or greater of consolidated sales	0	0	0	0
Number of crude oil suppliers	2	2	2	2
Percentage of crude oil supply from 2 suppliers	49.50%	44.00%	48.80%	46.00%

Subsequent Events - Narrative (

Subsequent Events - Narrative (Details) - Subsequent Event [Member] - USD ($) $ / shares in Units, $ in Millions	Aug. 14, 2015	Aug. 04, 2015	Jul. 21, 2015	Aug. 07, 2015
Subsequent Event [Line Items]
Gain (Loss) on Derivative				$ (3)
Derivative Liability, Fair Value, Amount Not Offset Against Collateral				(15)
Fair value of senior notes, increase (decrease)				$ 4
Dividend Declared [Member]
Subsequent Event [Line Items]
Date of quarterly cash distribution declared			Jul. 21, 2015
Quarterly distribution (in USD per share)			$ 0.685
Aggregate distribution			$ 57.3
Dividend Paid [Member]
Subsequent Event [Line Items]
Distribution payment date	Aug. 14, 2015
Distribution record date, close of business		Aug. 4, 2015
Distribution in aggregate on annualized basis (in USD per share)			$ 2.74
Aggregate distribution on an annualized basis			$ 229.2