Calumet Specialty Products Partners, L.P. - Quarter Report: 2019 September (Form 10-Q)

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

Emerging growth company

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q



☒	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2019



☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE TRANSITION PERIOD FROM TO

Commission File Number: 000-51734

Calumet Specialty Products Partners, L.P.

(Exact Name of Registrant as Specified in Its Charter)



Delaware		35-1811116
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer Identification Number)

2780 Waterfront Parkway East Drive, Suite 200
Indianapolis, Indiana		46214
(Address of Principal Executive Offices)		(Zip Code)

(317) 328-5660

(Registrant’s Telephone Number, Including Area Code)

None

(Former Name, Former Address and Former Fiscal Year, If Changed Since Last Report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒

Securities Registered Pursuant to Section 12(b) of the Act:



Title of each class	Trading symbol(s)	Name of each exchange on which registered
Common units representing limited partner interests	CLMT	The NASDAQ Stock Market LLC

On November 12, 2019, there were 77,560,355 common units outstanding.

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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

QUARTERLY REPORT

For the Three and Nine Months Ended September 30, 2019

Table of Contents



	Page
Part I
Item 1. Financial Statements
Condensed Consolidated Balance Sheets	4
Unaudited Condensed Consolidated Statements of Operations	5
Unaudited Condensed Consolidated Statements of Comprehensive Loss	6
Unaudited Condensed Consolidated Statements of Partners’ Capital	7
Unaudited Condensed Consolidated Statements of Cash Flows	8
Notes to Unaudited Condensed Consolidated Financial Statements	9
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	39
Item 3. Quantitative and Qualitative Disclosures About Market Risk	63
Item 4. Controls and Procedures	65
Part II
Item 1. Legal Proceedings	67
Item 1A. Risk Factors	67
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	67
Item 3. Defaults Upon Senior Securities	67
Item 4. Mine Safety Disclosures	67
Item 5. Other Information	67
Item 6. Exhibits	67

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FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q (this “Quarterly Report”) includes certain “forward-looking statements.” These statements can be identified by the use of forward-looking terminology including “may,” “intend,” “believe,” “expect,” “anticipate,” “estimate,” “continue,” “plan,” “should,” “could,” “would,” or other similar words. The statements regarding (i) estimated capital expenditures as a result of required audits or required operational changes or other environmental and regulatory liabilities, (ii) our anticipated levels of, use and effectiveness of derivatives to mitigate our exposure to crude oil price changes, natural gas price changes and fuel products price changes, (iii) estimated costs of complying with the U.S. Environmental Protection Agency’s (“EPA”) Renewable Fuel Standard (“RFS”), including the prices paid for Renewable Identification Numbers (“RINs”), (iv) our ability to meet our financial commitments, debt service obligations, debt instrument covenants, contingencies and anticipated capital expenditures, (v) our access to capital to fund capital expenditures and our working capital needs and our ability to obtain debt or equity financing on satisfactory terms, (vi) our access to inventory financing under our supply and offtake agreements, (vii) our ability to remediate the identified material weaknesses and further strengthen the overall controls surrounding information systems, (viii) the future effectiveness of our enterprise resource planning (“ERP”) system to further enhance operating efficiencies and provide more effective management of our business operations and (ix) the SEC investigation generally related to our finance and accounting staff, financial reporting, public disclosures, accounting policies, disclosure controls and procedures and internal controls, as well as other matters discussed in this Quarterly Report that are not purely historical data, are forward-looking statements. These forward-looking statements are based on our expectations and beliefs as of the date hereof concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our current expectations for future sales and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisition or disposition transactions. Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. Known material factors that could cause our actual results to differ from those in the forward-looking statements are those described in (i) Part I, Item 1A “Risk Factors” and Part II, Item 7A “Quantitative and Qualitative Disclosures About Market Risk” in our Annual Report on Form 10-K for the fiscal year ended December 31, 2018 (“2018 Annual Report”), (ii) Part II, Item 1A “Risk Factors” in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2019 and (iii) Part I, Item 3 “Quantitative and Qualitative Disclosures About Market Risk” and Part II, Item 1A “Risk Factors” in this Quarterly Report. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.

References in this Quarterly Report to “Calumet Specialty Products Partners, L.P.,” “Calumet,” “the Company,” “we,” “our,” “us” or like terms refer to Calumet Specialty Products Partners, L.P. and its subsidiaries. References in this Quarterly Report to “our general partner” refer to Calumet GP, LLC, the general partner of Calumet Specialty Products Partners, L.P.

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PART I

Item 1. Financial Statements

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

CONDENSED CONSOLIDATED BALANCE SHEETS



	September 30, 2019			December 31, 2018
	(Unaudited)
	(In millions, except unit data)
ASSETS
Current assets:
Cash and cash equivalents	$	164.2		$	155.7
Accounts receivable, net:
Trade	216.0			177.7
Other	24.7			20.3
	240.7			198.0
Inventories	293.3			284.1
Derivative assets	0.8			18.3
Prepaid expenses and other current assets	11.5			13.9
Total current assets	710.5			670.0
Property, plant and equipment, net	1,050.1			1,098.1
Investment in unconsolidated affiliates	5.7			25.4
Goodwill	171.4			171.4
Other intangible assets, net	75.4			88.0
Operating lease right-of-use assets	110.5			—
Other noncurrent assets, net	37.7			34.6
Total assets	$	2,161.3		$	2,087.5
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	270.2		$	200.6
Accrued interest payable	40.9			30.7
Accrued salaries, wages and benefits	31.9			25.7
Other taxes payable	21.2			15.2
Obligations under inventory financing agreements	117.0			105.3
Other current liabilities	70.4			33.8
Current portion of operating lease liabilities	62.3			—
Current portion of long-term debt	123.5			3.8
Total current liabilities	737.4			415.1
Pension and postretirement benefit obligations	4.5			4.5
Other long-term liabilities	1.5			1.5
Long-term operating lease liabilities	48.9			—
Long-term debt, less current portion	1,306.2			1,600.7
Total liabilities	2,098.5			2,021.8
Commitments and contingencies
Partners’ capital:
Limited partners’ interest 77,556,190 units and 77,177,159 units issued and outstanding as of September 30, 2019 and December 31, 2018, respectively	57.5			61.6
General partner’s interest	12.8			12.8
Accumulated other comprehensive loss	(7.5		)	(8.7		)
Total partners’ capital	62.8			65.7
Total liabilities and partners’ capital	$	2,161.3		$	2,087.5

See accompanying notes to unaudited condensed consolidated financial statements.

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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
	(In millions, except per unit and unit data)
Sales	$	929.6		$	953.5		$	2,677.8		$	2,649.5
Cost of sales	811.8			850.2			2,316.9			2,313.7
Gross profit	117.8			103.3			360.9			335.8
Operating costs and expenses:
Selling	12.6			12.2			40.2			39.6
General and administrative	32.8			29.2			105.5			95.5
Transportation	28.4			36.4			95.9			99.7
Taxes other than income taxes	5.7			5.9			15.5			13.2
Loss on impairment and disposal of assets	3.2			—			31.1			—
Other operating (income) expense	1.7			(2.0		)	0.8			(18.7		)
Operating income	33.4			21.6			71.9			106.5
Other income (expense):
Interest expense	(33.8		)	(37.7		)	(99.2		)	(120.4		)
Gain (loss) from debt extinguishment	—			—			0.7			(58.8		)
Gain (loss) on derivative instruments	(5.0		)	(2.7		)	14.4			(2.0		)
Other	1.3			3.2			7.9			5.6
Total other expense	(37.5		)	(37.2		)	(76.2		)	(175.6		)
Net loss from continuing operations before income taxes	(4.1		)	(15.6		)	(4.3		)	(69.1		)
Income tax expense from continuing operations	0.5			0.4			0.7			1.0
Net loss from continuing operations	$	(4.6	)	$	(16.0	)	$	(5.0	)	$	(70.1	)
Net loss from discontinued operations, net of tax	$	—		$	(0.5	)	$	—		$	(3.1	)
Net loss	$	(4.6	)	$	(16.5	)	$	(5.0	)	$	(73.2	)
Allocation of net loss:
Net loss	$	(4.6	)	$	(16.5	)	$	(5.0	)	$	(73.2	)
Less:
General partner’s interest in net loss	(0.1		)	(0.4		)	(0.1		)	(1.5		)
Net loss available to limited partners	$	(4.5	)	$	(16.1	)	$	(4.9	)	$	(71.7	)
Weighted average limited partner units outstanding:
Basic and diluted	78,299,472			77,783,879			78,174,976			77,643,006
Limited partners’ interest basic and diluted net loss per unit:
From continuing operations	$	(0.06	)	$	(0.20	)	$	(0.06	)	$	(0.88	)
From discontinued operations	—			(0.01		)	—			(0.04		)
Limited partners’ interest	$	(0.06	)	$	(0.21	)	$	(0.06	)	$	(0.92	)

See accompanying notes to unaudited condensed consolidated financial statements.

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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
	(In millions)
Net loss	$	(4.6	)	$	(16.5	)	$	(5.0	)	$	(73.2	)
Other comprehensive income:
Cash flow hedges:
Cash flow hedge loss reclassified to net loss	—			0.7			—			2.8
Defined benefit pension and retiree health benefit plans	—			—			—			0.1
Foreign currency translation adjustment	—			—			1.2			—
Total other comprehensive income	—			0.7			1.2			2.9
Comprehensive loss attributable to partners’ capital	$	(4.6	)	$	(15.8	)	$	(3.8	)	$	(70.3	)

See accompanying notes to unaudited condensed consolidated financial statements.

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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL



	Accumulated Other Comprehensive Loss			Partners’ Capital
	Accumulated Other Comprehensive Loss			General Partner			Limited Partners			Total
	(In millions)
Balance at June 30, 2019	$	(7.5	)	$	12.9		$	61.7		$	67.1
Net loss	—			(0.1		)	(4.5		)	(4.6		)
Amortization of phantom units	—			—			0.3			0.3
Balance at September 30, 2019	$	(7.5	)	$	12.8		$	57.5		$	62.8



	Accumulated Other Comprehensive Loss			Partners’ Capital
	Accumulated Other Comprehensive Loss			General Partner			Limited Partners			Total
	(In millions)
Balance at December 31, 2018	$	(8.7	)	$	12.8		$	61.6		$	65.7
Other comprehensive income	1.2			—			—			1.2
Net loss	—			(0.1		)	(4.9		)	(5.0		)
Amortization of phantom units	—			—			1.3			1.3
Settlement of tax withholdings on equity-based incentive compensation	—			—			(0.5		)	(0.5		)
Contributions from Calumet GP, LLC	—			0.1			—			0.1
Balance at September 30, 2019	$	(7.5	)	$	12.8		$	57.5		$	62.8



	Accumulated Other Comprehensive Loss			Partners’ Capital
	Accumulated Other Comprehensive Loss			General Partner			Limited Partners			Total
	(In millions)
Balance at June 30, 2018	$	(5.0	)	$	12.7		$	58.9		$	66.6
Other comprehensive income	0.7			—			—			0.7
Net loss	—			(0.4		)	(16.1		)	(16.5		)
Amortization of phantom units	—			—			0.7			0.7
Settlement of tax withholdings on equity-based incentive compensation	—			—			(0.3		)	(0.3		)
Balance at September 30, 2018	$	(4.3	)	$	12.3		$	43.2		$	51.2



	Accumulated Other Comprehensive Loss			Partners’ Capital
	Accumulated Other Comprehensive Loss			General Partner			Limited Partners			Total
	(In millions)
Balance at December 31, 2017	$	(7.2	)	$	13.8		$	113.3		$	119.9
Other comprehensive income	2.9			—			—			2.9
Net loss	—			(1.5		)	(71.7		)	(73.2		)
Amortization of phantom units	—			—			2.8			2.8
Settlement of tax withholdings on equity-based incentive compensation	—			—			(1.2		)	(1.2		)
Balance at September 30, 2018	$	(4.3	)	$	12.3		$	43.2		$	51.2

See accompanying notes to unaudited condensed consolidated financial statements.

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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS



	Nine Months Ended September 30,
	2019			2018
	(In millions)
Operating activities
Net loss	$	(5.0	)	$	(73.2	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Net loss from discontinued operations	—			3.1
Depreciation and amortization	82.6			88.8
Amortization of turnaround costs	16.5			8.7
Non-cash interest expense	4.9			6.1
(Gain) loss on debt extinguishments	(0.7		)	58.8
Unrealized (gain) loss on derivative instruments	20.2			(0.4		)
Equity based compensation	4.9			2.8
Lower of cost or market inventory adjustment	(38.8		)	(12.0		)
Loss on impairment and disposal of assets	31.1			—
Operating lease expense	57.1			—
Operating lease payments	(57.1		)	—
Other non-cash activities	(7.0		)	(3.0		)
Changes in assets and liabilities:
Accounts receivable	(49.8		)	29.0
Inventories	29.6			(34.4		)
Prepaid expenses and other current assets	4.6			(3.8		)
Derivative activity	(0.4		)	(0.4		)
Turnaround costs	(16.8		)	(11.1		)
Accounts payable	61.7			(32.5		)
Accrued interest payable	10.8			(7.0		)
Accrued salaries, wages and benefits	2.6			(4.5		)
Other taxes payable	6.0			8.5
Other liabilities	(3.1		)	(52.7		)
Pension and postretirement benefit obligations	—			(0.1		)
Net cash provided by (used in) operating activities	153.9			(29.3		)
Investing activities
Additions to property, plant and equipment	(27.4		)	(41.3		)
Investment in unconsolidated affiliate	—			(3.8		)
Proceeds from sale of unconsolidated affiliate	5.0			9.9
Proceeds from sale of business, net	—			44.8
Proceeds from sale of property, plant and equipment	3.7			0.3
Net cash provided by discontinued investing activities	5.0			3.6
Net cash provided by (used in) investing activities	(13.7		)	13.5
Financing activities
Proceeds from borrowings — revolving credit facility	—			166.8
Repayments of borrowings — revolving credit facility	—			(166.9		)
Repayments of borrowings — senior notes	(137.3		)	(400.0		)
Payments on finance lease obligations	(0.9		)	(2.2		)
Proceeds from inventory financing agreements	848.7			867.0
Payments on inventory financing agreements	(840.7		)	(850.6		)
Proceeds from other financing obligations	—			4.6
Payments on other financing obligations	(1.6		)	(2.3		)
Payments on extinguishment of debt	—			(46.6		)
Debt issuance costs	—			(2.9		)
Contributions from Calumet GP, LLC	0.1			0.1
Net cash used in financing activities	(131.7		)	(433.0		)
Net increase (decrease) in cash and cash equivalents	8.5			(448.8		)
Cash and cash equivalents at beginning of period	155.7			514.3
Cash and cash equivalents at end of period	$	164.2		$	65.5
Supplemental disclosure of non-cash investing activities
Non-cash property, plant and equipment additions	$	12.3		$	1.1

See accompanying notes to unaudited condensed consolidated financial statements.

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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. Description of the Business and Presentation of Financial Statements

Calumet Specialty Products Partners, L.P. (the “Company”) is a publicly traded Delaware limited partnership listed on the NASDAQ Global Select Market under the ticker symbol “CLMT.” The general partner of the Company is Calumet GP, LLC, a Delaware limited liability company. As of September 30, 2019, the Company had 77,556,190 limited partner common units and 1,582,779 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 the Company’s employees and the Company reimburses the general partner for certain of its expenses.

The Company is engaged in the production and marketing of crude oil-based specialty products including lubricating oils, white mineral oils, solvents, petrolatums, waxes, and fuel and fuel related products including gasoline, diesel, jet fuel, asphalt and heavy fuel oils. The Company is based in Indianapolis, Indiana and owns specialty and fuel products facilities. The Company owns and leases additional facilities, primarily related to production and marketing of specialty and fuel products, throughout the United States.

The unaudited condensed consolidated financial statements of the Company as of September 30, 2019 and for the three and nine months ended September 30, 2019 and 2018, included herein have been prepared, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). Certain information and disclosures normally included in the consolidated financial statements prepared in accordance with generally accepted accounting principles (“GAAP”) in the U.S. have been condensed or omitted pursuant to such rules and regulations, although the Company believes that the following disclosures are adequate to make the information presented not misleading. The preparation of the unaudited condensed consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the unaudited condensed consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. These unaudited condensed consolidated financial statements reflect all adjustments that, in the opinion of management, are necessary to present fairly the results of operations for the interim periods presented. All adjustments are of a normal nature, unless otherwise disclosed. The results of operations for the three and nine months ended September 30, 2019 are not necessarily indicative of the results that may be expected for the year ending December 31, 2019. These unaudited condensed consolidated financial statements should be read in conjunction with the Company’s 2018 Annual Report.

2. Summary of Significant Accounting Policies

Reclassifications

Certain amounts in the prior years’ unaudited condensed consolidated financial statements have been reclassified to conform to the current year presentation.

Other Current Liabilities

Other current liabilities consisted of the following (in millions):



	September 30, 2019		December 31, 2018
RINs Obligation	$	14.4	$	15.8
Other ⁽¹⁾	56.0		18.0
Total	$	70.4	$	33.8


⁽¹⁾	Balance as of September 30, 2019 includes $38.1 million related to the reclassification of the present value of the TexStar finance lease obligation in the first quarter of 2019 from current and long-term debt to other current liabilities. See Note 7 - “Commitments and Contingencies” for further information.

The Company’s Renewable Identification Numbers (“RINs”) obligation (“RINs Obligation”) represents a liability for the purchase of RINs to satisfy the EPA requirement to blend biofuels into the fuel products it produces pursuant to the EPA’s RFS. RINs are assigned to biofuels produced in the U.S. as required by the EPA. The EPA sets annual quotas for the percentage of biofuels that must be blended into transportation fuels consumed in the U.S. and, as a producer of motor fuels from petroleum, the Company is required to blend biofuels into the fuel products it produces at a rate that will meet the EPA’s annual quota. To the extent the Company is unable to blend biofuels at that rate, it must purchase RINs in the open market to satisfy the annual requirement. The Company’s RINs Obligation is based on the amount of RINs it must purchase and the price of those RINs as of the balance sheet date.

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The Company uses the inventory model to account for RINs, measuring acquired RINs at weighted-average cost. The cost of RINs used each period is charged to cost of sales with cash inflows and outflows recorded in the operating cash flow section of the unaudited condensed consolidated statements of cash flows. The liability is calculated by multiplying the RINs shortage (based on actual results) by the period end RIN spot price. The Company recognizes an asset at the end of each reporting period in which it has generated RINs in excess of its RINs Obligation. The asset is initially recorded at cost at the time the Company acquires them and are subsequently revalued at the lower of cost or market as of the last day of each accounting period and the resulting adjustments are reflected in cost of sales for the period in the unaudited condensed consolidated statements of operations. The value of RINs in excess of the RINs Obligation, if any, would be reflected in other current assets on the condensed consolidated balance sheets. RINs generated in excess of the Company’s current RINs Obligation may be sold or held to offset future RINs Obligations. Any such sales of excess RINs are recorded in cost of sales in the unaudited condensed consolidated statements of operations. The liabilities associated with the Company’s RINs Obligation are considered recurring fair value measurements. See Note 7 - “Commitments and Contingencies” for further information on the Company’s RINs Obligation.

Adopted Accounting Pronouncements

On January 1, 2019, the Company adopted ASU No. 2016-02, Leases (Topic 842) (“ASU 2016-02”) and all the related amendments to its lease contracts using the modified retrospective method. The effective date was used as the Company’s date of initial application with no restatement of prior periods. As such, prior periods continue to be reported under the accounting standards in effect for those periods. See Note 14 - “Leases” for further information.

On January 1, 2019, the Company adopted ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities, which improves the financial reporting of hedging relationships to better align risk management activities in financial statements and make certain targeted improvements to simplify the application of the hedge accounting guidance in current GAAP. Given the Company’s current risk management strategy of not designating any of its derivative positions as hedges, the adoption of this guidance had no effect on our consolidated financial statements. If, in the future, the Company decides to modify its hedging strategies, this new accounting guidance would become applicable and will be applied at that time.

On January 1, 2019, the Company adopted ASU No. 2018-07, Compensation — Stock Compensation (Topic 718): Improvements to Nonemployee Share-Based Payment Accounting (“ASU 2018-07”). This update simplifies the guidance related to nonemployee share-based payments by superseding ASC 505-50 and expanding the scope of ASC 718 to include all share-based payment arrangements related to the acquisition of goods and services from both nonemployees and employees. Prior to the issuance of this standard update, nonemployee share-based payments were subject to ASC 505-50 requirements while employee share-based payments were subject to ASC 718 requirements. ASU 2018-07 is effective for fiscal years (including interim periods) beginning after December 15, 2018, with early adoption permitted. The adoption of ASU 2018-07 had no impact on the Company’s condensed consolidated financial statements.

3. Revenue Recognition

The following is a description of principal activities from which the Company generates revenue. Revenues are recognized when control of the promised goods are transferred to the customer, in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods. To determine revenue recognition for arrangements that an entity determines are within the scope of ASC 606, the Company performs the following five steps: (i) identify the contract(s) with a customer; (ii) identify the performance obligations in the contract; (iii) determine the transaction price; (iv) allocate the transaction price to the performance obligations in the contract; and (v) recognize revenue when (or as) the entity satisfies a performance obligation. At contract inception, once the contract is determined to be within the scope of ASC 606, the Company assesses the goods promised within each contract and determines the performance obligations and assesses whether each promised good is distinct. The Company then recognizes as revenue the amount of the transaction price that is allocated to the respective performance obligation when (or as) the performance obligation is satisfied.

Products

The Company is engaged in the production and marketing of crude oil-based specialty products including lubricating oils, white mineral oils, solvents, petrolatums, waxes and other products which comprise the specialty products segment. The Company is also engaged in the production of fuel and fuel related products including gasoline, diesel, jet fuel, asphalt and other products which comprise the fuel products segment.

The Company considers customer purchase orders, which in some cases are governed by master sales agreements, to be the contracts with a customer. For each contract, the Company considers the promise to transfer products, each of which are distinct, to be the identified performance obligations. In determining the transaction price, the Company evaluates whether the price is subject to variable consideration such as product returns, rebates or other discounts to determine the net consideration to which the Company expects to be entitled. The Company transfers control and recognizes revenue upon shipment to the customer or, in certain cases, upon receipt by the customer in accordance with contractual terms.

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Excise and Sales Taxes

The Company assesses, collects and remits excise taxes associated with the sale of certain of its fuel products. Furthermore, the Company collects and remits sales taxes associated with certain sales of its products to non-exempt customers. The Company excludes excise taxes and sales taxes that are collected from customers from the transaction price in its contracts with customers. Accordingly, revenue from contracts with customers is net of sales-based taxes that are collected from customers and remitted to taxing authorities.

Shipping and Handling Costs

Shipping and handling costs are deemed to be fulfillment activities rather than a separate distinct performance obligation.

Cost of Obtaining Contracts

The Company may incur incremental costs to obtain a sales contract, which under ASC 606 should be capitalized and amortized over the life of the contract. The Company has elected to apply the practical expedient in ASC 340-40-50-5 allowing the Company to expense these costs since the contracts are short-term in nature with a contract term of one year or less.

Disaggregation of Revenue

The following table reflects the disaggregation of revenue by major source (in millions):



	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
Sales by major source
Standard specialty products	$	296.2	$	285.2	$	872.2	$	848.7
Packaged and synthetic specialty products	59.6		64.0		180.2		204.9
Total specialty products	$	355.8	$	349.2	$	1,052.4	$	1,053.6

Fuel and fuel related products	$	508.4	$	525.9	$	1,446.3	$	1,422.2
Asphalt	65.4		78.4		179.1		173.7
Total fuel products	$	573.8	$	604.3	$	1,625.4	$	1,595.9

Total sales	$	929.6	$	953.5	$	2,677.8	$	2,649.5

Revenue is recognized when obligations under the terms of a contract with a customer are satisfied; recognition generally occurs with the transfer of control at a point in time. The contract with the customer states the final terms of the sale, including the description, quantity and price of each product or service purchased. For fuel products, payment is typically due in full between 2 to 30 days of delivery or the start of the contract term, such that payment is typically collected 2 to 30 days subsequent to the satisfaction of performance obligations. For specialty products, payment is typically due in full between 30 to 90 days of delivery or the start of the contract term, such that payment is typically collected 30 to 90 days subsequent to the satisfaction of performance obligations. In the normal course of business, the Company does not accept product returns unless the item is defective as manufactured. The expected costs associated with a product assurance warranty continues to be recognized as expense when products are sold. The Company does not offer promised services that could be considered warranties that are sold separately or provide a service in addition to assurance that the related product complies with agreed upon specifications. The Company establishes provisions based on the methods described in ASC 606 for estimated returns and warranties as variable consideration when determining the transaction price.

Contract Balances

Under product sales contracts, the Company invoices customers for performance obligations that have been satisfied, at which point payment is unconditional. Accordingly, a product sales contract does not give rise to contract assets or liabilities under ASC 606. The Company’s receivables, net of allowance for doubtful accounts, from contracts with customers as of September 30, 2019 and December 31, 2018 was $216.0 million and $177.7 million, respectively.

Transaction Price Allocated to Remaining Performance Obligations

The Company’s product sales are short-term in nature with a contract term of one year or less. The Company has utilized the practical expedient in ASC 606-10-50-14 exempting the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. Additionally, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

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4. 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. In certain circumstances, the Company may decide not to replenish inventory for certain products or product lines during an interim period, in which case, the Company may record interim LIFO adjustments during that period. During the nine months ended September 30, 2019, the Company recorded increases (exclusive of lower of cost or market (“LCM”) adjustments) in cost of sales in the unaudited condensed consolidated statements of operations of $0.9 million due to the permanent liquidation of inventory layers. No such activity occurred in the three months ended September 30, 2019 or in the three and nine months ended September 30, 2018.

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 $15.8 million higher and $7.8 million lower as of September 30, 2019 and December 31, 2018, respectively.

On March 31, 2017 and June 19, 2017, the Company sold inventory comprised of crude oil and refined products to Macquarie Energy North America Trading Inc. (“Macquarie”) under Supply and Offtake Agreements as described in Note 8 — “Inventory Financing Agreements” related to the Great Falls and Shreveport refineries, respectively. The crude oil remains in the legal title of Macquarie and is stored in the Company’s refinery storage tanks governed by storage agreements. Legal title to the crude oil passes to the Company at the storage tank outlet for processing into refined products. After processing, Macquarie takes title to the refined products stored in the Company’s storage tanks until sold to third parties. While title to certain inventories will reside with Macquarie, the Supply and Offtake Agreements are accounted for by the Company similar to a product financing arrangement; therefore, the inventories sold to Macquarie will continue to be included in the Company’s condensed consolidated balance sheets until processed and sold to a third party. The Company is obligated to repurchase the inventory in certain scenarios.

Inventories consist of the following (in millions):



	September 30, 2019						December 31, 2018
	Titled Inventory		Supply and Offtake Agreements ⁽¹⁾		Total		Titled Inventory		Supply and Offtake Agreements ⁽¹⁾		Total
Raw materials	$	43.9	$	14.7	$	58.6	$	41.8	$	10.6	$	52.4
Work in process	37.0		32.7		69.7		40.7		19.2		59.9
Finished goods	112.1		52.9		165.0		127.9		43.9		171.8
	$	193.0	$	100.3	$	293.3	$	210.4	$	73.7	$	284.1


⁽¹⁾	Amounts represent LIFO value and do not necessarily represent the value of product financing. Refer to Note 8 - “Inventory Financing Agreements” for further information.

Under the LIFO inventory method, the most recently incurred costs are charged to cost of sales and inventories are valued at the earliest acquisition costs. 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. During the three months ended September 30, 2019 and 2018, the Company realized increases of $2.7 million and $3.0 million, respectively, in cost of sales in the unaudited condensed consolidated statements of operations due to the sale of previously adjusted inventory. During the nine months ended September 30, 2019 and 2018, the Company realized decreases of $38.8 million and $12.0 million, respectively, in cost of sales in the unaudited condensed consolidated statements of operations due to the sale of previously adjusted inventory.

5. Discontinued Operations

On November 21, 2017, Calumet Operating, LLC, a Delaware limited liability company and a wholly-owned subsidiary of the Company, completed the sale to a subsidiary of Q’Max Solutions Inc. (“Q’Max”) of all of the issued and outstanding membership interests in Anchor Drilling Fluids USA, LLC (“Anchor”), for total consideration of approximately $85.5 million including a base price of $50.0 million, $14.2 million for net working capital and other items and a 10% equity interest in Fluid Holding Corp. (“FHC”), the parent company of Q’Max (the “Anchor Transaction”). Effective in its fourth quarter of 2017, the Company classified its results of operations for all periods presented to reflect Anchor as a discontinued operation and classified the assets and liabilities of Anchor as discontinued operations. Prior to being reported as discontinued operations, Anchor was included as its own reportable segment as oilfield services.

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As of September 30, 2019 and December 31, 2018, the Company had a $6.1 million and an $11.1 million receivable, respectively, in other accounts receivable in the condensed consolidated balance sheets for the remaining payment of the base price and working capital.

On October 31, 2019, Q’Max and the Company agreed to restructure the remaining amount of the receivable to be paid with the final payment due on June 30, 2021. The $6.1 million will be paid with an initial payment of approximately $0.3 million paid upon signing the agreement with subsequent monthly payments beginning December 30, 2019. In addition to the payments of principal, Q’Max shall pay interest at a rate of 6% per annum.

The following table summarizes the results of discontinued operations for the periods presented (in millions):



	Three Months Ended September 30,			Nine Months Ended September 30,
	2018
Other	(0.5		)	(3.1		)
Net loss from discontinued operations net of income taxes	$	(0.5	)	$	(3.1	)

6. Investment in Unconsolidated Affiliates

The following table summarizes the Company’s investments in unconsolidated affiliates (in millions):



	September 30, 2019		December 31, 2018
Fluid Holding Corp.	5.7		25.4
Total	$	5.7	$	25.4

Fluid Holding Corp.

In connection with the Anchor Transaction in November 2017, the Company received an equity investment in FHC as part of the total consideration for Anchor. FHC provides oilfield services and products to customers globally. The Company’s investment in FHC is a non-marketable equity security without a readily determinable fair value. The Company records this investment using a measurement alternative which values the security at cost less impairment, if any, plus or minus changes resulting from qualifying observable price changes with a same or similar security from the same issuer.

During the three months ended June 30, 2019, the Company determined the fair value of its investment in FHC was less than its carrying value of $25.4 million after evaluating indicators of impairment and valuing the investment using projected future cash flows and other Level 3 inputs. Utilizing an income approach, value indications are developed by discounting expected cash flows to their present value at a rate of return that incorporates the risk-free rate for the use of funds, the expected rate of inflation and risks associated with the company. As a result, the Company recorded an impairment charge of $16.1 million in loss on impairment and disposal of assets in the unaudited condensed consolidated statements of operations for the three months ended June 30, 2019.

During the three months ended September 30, 2019, the Company determined the fair value of its investment in FHC was less than its carrying value of $9.3 million as a result of a preferred stock issuance by FHC, which diluted the Company’s ownership percentage. As a result, the Company recorded an impairment charge of $3.6 million in loss on impairment and disposal of assets in the unaudited condensed consolidated statements of operations for the three months ended September 30, 2019 and a $19.7 million impairment charge for the nine months ended September 30, 2019.

Biosyn Holdings, LLC and Biosynthetic Technologies

In February 2018, the Company and The Heritage Group formed Biosyn Holdings, LLC (“Biosyn”) for the purpose of acquiring Biosynthetic Technologies, LLC (“Biosynthetic Technologies”), a startup company which developed an intellectual property portfolio for the manufacture of renewable-based and biodegradable esters. In March 2019, the Company sold its investment in Biosyn to The Heritage Group, a related party, for total proceeds of $5.0 million which was recorded in the “other” component of other income (expense) on the unaudited condensed consolidated statements of operations. Prior to the sale of Biosyn, the Company accounted for its ownership in Biosyn under the equity method of accounting.

7. 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 taxation and regulatory authorities, such as the Internal Revenue Service, the EPA and the U.S. Occupational Safety and Health Administration (“OSHA”), as well as various state environmental regulatory bodies and state and local departments of revenue, 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.

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Environmental

The Company conducts crude oil and specialty hydrocarbon refining, blending and terminal operations and such activities are subject to stringent federal, regional, state and local laws and regulations governing worker health and safety, the discharge of materials into the environment and environmental protection. These laws and regulations impose obligations that are applicable to the Company’s operations, such as requiring the acquisition of permits to conduct regulated activities, restricting the manner in which the Company may release materials into the environment, requiring remedial activities or capital expenditures to mitigate pollution from former or current operations, requiring the application of specific health and safety criteria addressing worker protection and imposing substantial liabilities for pollution resulting from its operations. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil and criminal penalties; the imposition of investigatory, remedial or corrective action obligations or the incurrence of capital expenditures; the occurrence of delays in the permitting, development or expansion of projects and the issuance of injunctive relief limiting or prohibiting Company activities. Moreover, certain of these laws impose joint and several, strict liability for costs required to remediate and restore sites where petroleum hydrocarbons, wastes or other materials have been released or disposed. In addition, new laws and regulations, new interpretations of existing laws and regulations, increased governmental enforcement or other developments, some of which legal requirements are discussed below, could significantly increase the Company’s operational or compliance expenditures.

Remediation of subsurface contamination is in process at certain of the Company’s refinery sites and is being overseen by the appropriate state agencies. Based on current investigative and remedial activities, the Company believes that the soil and groundwater contamination at these refineries can be controlled or remediated without having a material adverse effect on the Company’s financial condition. However, such costs are often unpredictable and, therefore, there can be no assurance that the future costs will not become material.

Great Falls Refinery

In connection with the acquisition of the Great Falls refinery from Connacher Oil and Gas Limited (“Connacher”), the Company became a party to an existing 2002 Refinery Initiative Consent Decree (the “Great Falls Consent Decree”) with the EPA and the Montana Department of Environmental Quality. The material obligations imposed by the Great Falls Consent Decree have been completed. On September 27, 2012, Montana Refining Company, Inc. received a final Corrective Action Order on Consent, replacing the refinery’s previously held hazardous waste permit. This Corrective Action Order on Consent governs the investigation and remediation of contamination at the Great Falls refinery. The Company believes the majority of damages related to such contamination at the Great Falls refinery are covered by a contractual indemnity provided by a subsidiary of HollyFrontier Corporation (the “Seller”), the owner and operator of the Great Falls refinery prior to its acquisition by Connacher, under an asset purchase agreement between the Seller and Connacher, pursuant to which Connacher acquired the Great Falls refinery. Under this asset purchase agreement, the Seller 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 the Seller’s ownership and operation of the Great Falls refinery and existing as of the date of sale to Connacher. During 2014, the Seller provided the Company a notice challenging the Company’s position that the Seller is obligated to indemnify the Company’s remediation expenses for environmental conditions to the extent arising under the Seller’s ownership and operation of the refinery and existing as of the date of sale to Connacher, which expenditures totaled in excess of $17.0 million as of September 30, 2019, of which $14.6 million was capitalized into the cost of the Company’s refinery expansion project and the remainder was expensed. On September 22, 2015, the Company initiated a lawsuit against the Seller. On November 24, 2015, the Seller filed a motion to dismiss the case pending arbitration. On February 10, 2016, the court ordered that all of the claims be addressed in arbitration. The arbitration panel conducted the first phase of the arbitration in July 2018 and issued its ruling on September 13, 2018. In its ruling, the arbitration panel confirmed that the Seller retained the liability for all pre-closing contamination with respect to third-party claims indefinitely and with respect to first party claims for which the Seller received notice within five years after the sale of the refinery, which claims are subject to the requirements otherwise set forth in the asset purchase agreement. The second phase of the arbitration regarding damages occurred in April 2019. The arbitration panel issued its final ruling on August 25, 2019. Among other things, the panel denied the Company’s demands for reimbursement for costs incurred and left open the Company’s ability to make future claims. The Company expects that it may incur costs to remediate other environmental conditions at the Great Falls refinery. The Company currently believes that these other costs it may incur will not be material to its financial position or results of operations.

Cotton Valley, Princeton and Shreveport Refineries

Since 2013, the Louisiana Depart of Environmental Quality (“LDEQ”) has issued Consolidated Compliance Orders & Notices of Proposed Penalties to the Cotton Valley, Princeton and Shreveport refineries relating to various alleged air quality and wastewater regulatory violations. The Company has responded to the various orders and has submitted a consolidated proposal to the LDEQ to resolve all of the applicable matters and it is likely a resolution of this matter will result in a penalty in excess of $0.1 million. The Company is awaiting a response from LDEQ on the Company’s proposal. The Company expects that the amount of the penalty will not be material to its financial position or results of operations and any conditions established by LDEQ on the Company’s operations will not be material to the Company’s operations.

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Renewable Identification Numbers Obligation

In August 2019, the EPA granted the Company’s fuel products refineries a “small refinery exemption” under the RFS for the compliance year 2018, as provided for under the federal Clean Air Act, as amended (“CAA”). In granting those exemptions, the EPA, in consultation with the Department of Energy, determined that for the compliance year 2018, compliance with the RFS would represent a “disproportionate economic hardship” for these small refineries.

In March 2018, the EPA granted the Company’s fuel products refineries a “small refinery exemption” under the RFS for the compliance year 2017, as provided for under the CAA. In granting those exemptions, the EPA, in consultation with the Department of Energy, determined that for the compliance year 2017, compliance with the RFS would represent a “disproportionate economic hardship” for these small refineries.

The RINs exemptions resulted in a decrease in the RINs Obligation and are a charge to cost of sales in the unaudited condensed consolidated statements of operations with the exception of the RINs exempted under the RFS for compliance year 2017 related to the Superior Refinery, which was charged to other (income) expense within operating income in the unaudited condensed consolidated statements of operations for the nine months ended September 30, 2018. As of September 30, 2019 and December 31, 2018, the Company had a RINs Obligation of $14.4 million and $15.8 million, respectively.

Occupational Health and Safety

The Company is subject to various laws and regulations relating to occupational health and safety, including the federal Occupational Safety and Health Act, as amended, 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, the EPA’s community right-to-know regulations under Title III of the federal Comprehensive Environmental Response, Compensation and Liability Act, as amended, and similar state statutes require the Company to maintain information about hazardous materials used or produced in the Company’s operations and provide this information to employees, contractors, state and local government authorities and customers. The Company maintains safety and training programs as part of its ongoing efforts to promote compliance with applicable laws and regulations. The Company conducts periodic audits of Process Safety Management systems at each of its locations subject to this 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.

Labor Matters

The Company has employees covered by various collective bargaining agreements. The below facilities ratified their collective bargaining agreements during the nine months ended September 30, 2019 and extended the agreements through the below expiration dates:



Facility/ Refinery	Union	Expiration Date
Cotton Valley	International Union of Operating Engineers	January 15, 2023
Shreveport	United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied-Industrial and Service Workers International Union	April 30, 2022
Missouri	United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied-Industrial and Service Workers International Union	April 30, 2022
Great Falls	United Steel, Paper and Forestry, Rubber, Manufacturing, Energy Allied-Industrial and Service Workers International Union	July 31, 2022

Other Matters, Claims and Legal Proceedings

The Company was a party to a 2014 Throughput and Deficiency Agreement with TexStar Midstream Logistics, L.P. (“TexStar”) pursuant to which TexStar delivered crude oil to the Company’s San Antonio refinery through a crude oil pipeline system owned and operated by TexStar (the “Pipeline Agreement”). The Pipeline Agreement had an initial term of 20 years and was accounted for as a finance lease on the Company’s condensed consolidated balance sheets. TexStar and the Company have each terminated the Pipeline Agreement for alleged breaches of the agreement. The Company ceased using the asset as of February 28, 2019, wrote off the associated net book value of $10.7 million in loss on impairment and disposal of assets and reclassified the $38.1 million present value of financing lease obligation from current and long-term debt to other current liabilities on the condensed consolidated balance sheets. The Company is in dispute with TexStar over whether any additional monies are owed with TexStar claiming certain minimum amounts of $0.0 to $0.5 million a month continued to be owed through the remainder of the original term of the Pipeline Agreement. The Company filed a lawsuit against TexStar on May 17, 2019 in Bexar County, Texas, seeking a declaratory judgment that the Company properly terminated the Pipeline Agreement and the Company is not obligated to make further payments under the Pipeline Agreement. The litigation is currently pending. The Company believes it will prevail in the dispute over whether further payments are owed, but pending resolution, the $38.1 million liability is recorded as a current liability on its condensed

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consolidated balance sheets. On November 10, 2019, the Company, TexStar, and related parties entered into a Settlement and Release Agreement with respect to the litigation. Please see Note 15 - “Subsequent Events” for further information.

On October 31, 2018, the Company received an indemnity claim notice (the “Claim Notice”) from Husky Superior Refining Holding Corp. (“Husky”) under the Membership Interest Purchase Agreement, dated August 11, 2017 (the “MIPA”), which was entered into in connection with the disposition of the Superior Refinery. The Claim Notice relates to alleged losses Husky incurred in connection with a fire at the Husky Superior refinery on April 26, 2018, over five months after Calumet sold Husky 100% of the membership interests in the entity that owns the Husky Superior refinery. Calumet understands the fire occurred during a turnaround of the Husky Superior refinery at a time when Husky owned, operated, and supervised the refinery. Calumet was not involved with the turnaround. The U.S. Chemical Safety and Hazard Investigation Board (“CSB”) is currently investigating the fire but has not contacted Calumet in connection with that investigation or suggested that Calumet is responsible for the fire. Husky’s Claim Notice alleges that Husky “has become aware of facts which may give rise to losses” for which it reserved the right to seek indemnification at a later date. The Claim Notice further alleges breaches of certain representations, warranties, and covenants contained in the MIPA. We believe that the information currently publicly available about the fire and the CSB investigation does not support Husky’s threatened claims, and Husky has not filed a lawsuit against Calumet. If Husky were to seek recourse under the MIPA for such claims, they would be subject to certain limits on indemnification liability that may reduce or eliminate any potential indemnification liability.

On July 9, 2019, Calumet Shreveport Refining, LLC entered into a Settlement Agreement and Mutual Release with Enterprise TE Products Pipeline Company LLC and Enterprise Refined Products Company LLC to resolve disputes regarding transportation charges, product downgrades and transmix recovery fee charges, and truck terminal loading charges that arose between the parties under the Transportation Agreement dated July 1, 2015. In July 2019, the final settlement amount actually paid by the Company to Enterprise TE Products Pipeline Company LLC and Enterprise Refined Products Company LLC, collectively, was $3.7 million.

On May 4, 2018, the SEC requested that the Company and certain of its executives voluntarily produce certain communications and documents prepared or maintained from January 2017 to May 2018 and generally related to the Company’s finance and accounting staff, financial reporting, public disclosures, accounting policies, disclosure controls and procedures and internal controls. Beginning on July 11, 2018, the SEC issued several subpoenas formally requesting the same documents previously subject to the voluntary production requests by the SEC as well as additional, related documents and information. The SEC has also interviewed and taken testimony from current and former Company employees and other individuals. The Company has, from the outset, cooperated with the SEC’s requests. The Company believes that the investigation is substantially completed, and has executed a formal settlement offer which it expects to resolve the matter, subject to final approval by the SEC Commissioners. The Company currently expects the investigation to conclude in the fourth quarter of 2019 and does not expect the resolution, including any fines or penalties, to have a material adverse effect on the Company’s financial condition or results of operations.

The Company is subject to other matters, claims and litigation incidental to its business. The Company has recorded accruals with respect to certain of its matters, claims and litigation where appropriate, that are reflected in the unaudited condensed consolidated financial statements but are not individually considered material. For other matters, claims and litigation, 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 matters, claims and litigation currently pending cannot be determined, the Company currently does not expect these outcomes, individually or in the aggregate (including matters for which the Company has recorded accruals), to have a material adverse effect on its financial position, results of operations or cash flows. The outcome of any matter, claim or 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.

Transactions with Related Parties

On April 18, 2019, the Company entered into a Master Reimbursement Agreement with The Heritage Group whereby The Heritage Group may incur or pay certain fees, expenses or obligations on behalf of the Company, and the Company shall reimburse The Heritage Group for such incurrences or payments in either cash or common units of the Company, subject to a limit of 4.0 million units valued at $3.60 per unit. As of September 30, 2019, the Company has accrued approximately $2.4 million for expenses incurred by The Heritage Group on behalf of the Company.

Standby Letters of Credit

The Company has agreements with various financial institutions for standby letters of credit, which have been issued primarily to vendors. As of September 30, 2019 and December 31, 2018, the Company had outstanding standby letters of credit of $70.1 million and $35.1 million, respectively, under its revolving credit facility. Refer to Note 9 - “Long-Term Debt” for additional information regarding the Company’s revolving credit facility. At September 30, 2019 and December 31, 2018, 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 $300.0 million, which amount may be increased with the consent of the Agent

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(as defined in the revolving credit facility agreement) to 90% of revolver commitments then in effect ($600.0 million at September 30, 2019 and December 31, 2018).

Throughput Contract

The Company has entered into a long-term agreement to transport crude oil at a minimum of 5,000 bpd through a pipeline yet to be constructed. The agreement also contains a capital recovery charge that increases 2% per annum. This agreement is for seven years commencing once the pipeline is in service. This agreement was entered into primarily to transport crude to our San Antonio Refinery. Please see Note 15 - “Subsequent Events” for further information.

As of September 30, 2019, the estimated minimum unconditional purchase commitments under this agreement were as follows (in millions):



Year	Commitment
2020	$	3.6
2021	3.4
2022	3.1
2023	2.9
2024	2.7
Thereafter	4.9
Total	$	20.6

8. Inventory Financing Agreements

On March 31, 2017, the Company entered into several agreements with Macquarie to support the operations of the Great Falls refinery (the “Great Falls Supply and Offtake Agreements”). On July 27, 2017, the Company amended the Great Falls Supply and Offtake Agreements to provide Macquarie the option to terminate the Great Falls Supply and Offtake Agreements effective nine months after the end of the applicable calendar quarter in which Macquarie elects to terminate and the Company has the option to terminate with ninety days’ notice at any time. On May 9, 2019, the Company entered into an amendment to the Great Falls Supply and Offtake Agreements to, among other things, extend the Expiration Date (as defined in the Great Falls Supply and Offtake Agreements) from September 30, 2019 to June 30, 2023.

On June 19, 2017, the Company entered into several agreements with Macquarie to support the operations of the Shreveport refinery (the “Shreveport Supply and Offtake Agreements” and together with the Great Falls Supply and Offtake Agreements, the “Supply and Offtake Agreements”). Since inception, the Shreveport Supply and Offtake Agreements were set to expire on June 30, 2020; however, Macquarie has the option to terminate the Shreveport Supply and Offtake Agreements effective nine months after the end of the applicable calendar quarter in which Macquarie elects to terminate and the Company has the option to terminate with ninety days’ notice at any time. On May 9, 2019, the Company entered into an amendment to the Shreveport Supply and Offtake Agreements to, among other things, extend the Expiration Date (as defined in the Shreveport Supply and Offtake Agreements) from June 30, 2020 to June 30, 2023.

The Supply and Offtake Agreements allow the Company to purchase crude oil from Macquarie or one of its affiliates. Per the Supply and Offtake Agreements, Macquarie will provide up to 30,000 barrels per day of crude oil to the Great Falls refinery and 60,000 barrels per day of crude oil to the Shreveport refinery. The Company agreed to purchase the crude oil on a just-in-time basis to support the production operations at the Great Falls and Shreveport refineries. Additionally, the Company agreed to sell, and Macquarie agreed to buy, at market prices, refined products produced at the Great Falls and Shreveport refineries. For Shreveport, finished products consisting of finished fuel products (other than jet fuel), lubricants and waxes, Macquarie may (but is not required to) sell such products to the sales intermediation party (“SIP”), and the SIP may (but is not required to) sell such products to Shreveport, as applicable, for sale in turn to third parties. For jet fuel and certain intermediate products, Macquarie may (but is not required to) sell such products to Shreveport for sale thereby to third parties. The Company will then repurchase the refined products from Macquarie or the SIP prior to selling the refined products to third parties.

The Supply and Offtake Agreements are subject to minimum and maximum inventory levels. The agreements also provide for the lease to Macquarie of crude oil and certain refined product storage tanks located at the Great Falls and Shreveport refineries and certain offsite locations. Following expiration or termination of the agreements, Macquarie has the option to require the Company to purchase the crude oil and refined product inventories then owned by Macquarie and located at the leased storage tanks at then current market prices. In addition, barrels owned by the Company are pledged as collateral to support the Deferred Payment Arrangement (defined below) obligations under these agreements.

While title to certain inventories will reside with Macquarie, the Supply and Offtake Agreements are accounted for by the Company similar to a product financing arrangement; therefore, the inventories sold to Macquarie will continue to be included in

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the Company’s condensed consolidated balance sheets until processed and sold to a third party. Each reporting period, the Company will record liabilities in an amount equal to the amount the Company expects to pay to repurchase the inventory held by Macquarie based on market prices at the termination date included in obligations under inventory financing agreements in the condensed consolidated balance sheets. The Company has determined that the redemption feature on the initially recognized liabilities related to the Supply and Offtake Agreements is an embedded derivative indexed to commodity prices. As such, the Company has accounted for these embedded derivatives at fair value with changes in the fair value, if any, recorded in gain (loss) on derivative instruments in the Company’s unaudited condensed consolidated statements of operations. For more information on the valuation of the associated derivatives, see Note 10 - “Derivatives” and Note 11 - “Fair Value Measurements.” The embedded derivatives will be recorded in obligations under inventory financing agreements on the condensed consolidated balance sheets. The cash flow impact of the embedded derivatives will be classified as a change in inventory financing activity in the financing activities section in the unaudited condensed consolidated statements of cash flows.

For the three months ended September 30, 2019 and 2018, the Company incurred $5.6 million and $6.3 million, respectively, for financing costs related to the Supply and Offtake Agreements, which are included in interest expense in the Company’s unaudited condensed consolidated statements of operations. For the nine months ended September 30, 2019 and 2018, the Company incurred $11.7 million and $13.4 million, respectively, for financing costs related to the Supply and Offtake Agreements which are included in interest expense in the Company’s unaudited condensed consolidated statements of operations.

The Company has provided collateral of $9.7 million related to the initial purchase of the Great Falls and Shreveport inventory to cover credit risk for future crude oil deliveries and potential liquidation risk if Macquarie exercises its rights and sells the inventory to third parties. The collateral was recorded as a reduction to the obligations under inventory financing agreements pursuant to a master netting agreement.

The Supply and Offtake Agreements also include a deferred payment arrangement (“Deferred Payment Arrangement”) whereby the Company can defer payments on just-in-time crude oil purchases from Macquarie owed under the agreements up to the value of the collateral provided (up to 90% of the collateral inventory). The deferred amounts under the Deferred Payment Arrangement will bear interest at a rate equal to the London Interbank Offered Rate (“LIBOR”) plus 3.25% per annum for both Shreveport and Great Falls. Amounts outstanding under the Deferred Payment Arrangement are included in obligations under inventory financing agreements in the Company’s condensed consolidated balance sheets. Changes in the amount outstanding under the Deferred Payment Arrangement are included within cash flows from financing activities on the unaudited condensed consolidated statements of cash flows. As of September 30, 2019 and December 31, 2018, the Company had $22.2 million and $20.4 million deferred payments outstanding, respectively. In addition to the Deferred Payment Arrangement, Macquarie has advanced the Company an additional $5.0 million which remains outstanding as of September 30, 2019.

9. Long-Term Debt

Long-term debt consisted of the following (in millions):



	September 30, 2019			December 31, 2018
Borrowings under third amended and restated senior secured revolving credit agreement with third-party lenders, interest payments quarterly, borrowings due February 2023, weighted average interest rate of 0.2% and 6.0% for the nine months ended September 30, 2019 and year ended December 31, 2018, respectively.	$	—		$	—
Borrowings under 2021 Notes, interest at a fixed rate of 6.50%, interest payments semiannually, borrowings due April 2021, effective interest rate of 6.8% for each of the nine months ended September 30, 2019 and the year ended December 31, 2018.	761.2			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 8.1% and 8.0% for the nine months ended September 30, 2019 and the year ended December 31, 2018, respectively. ⁽¹⁾	351.2			351.6
Borrowings under 2023 Notes, interest at a fixed rate of 7.75%, interest payments semiannually, borrowings due April 2023, effective interest rate of 8.1% and 8.0% for the nine months ended September 30, 2019 and the year ended December 31, 2018, respectively.	325.0			325.0
Other	4.1			5.2
Finance lease obligations, at various interest rates, interest and monthly principal payments⁽³⁾	2.8			42.4
Less unamortized debt issuance costs ⁽²⁾	(11.5		)	(15.8		)
Less unamortized discounts	(3.1		)	(3.9		)
Total long-term debt	$	1,429.7		$	1,604.5
Less current portion of long-term debt ⁽⁴⁾	123.5			3.8
	$	1,306.2		$	1,600.7

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⁽¹⁾	The balance includes a fair value interest rate hedge adjustment, which increased the debt balance by $1.2 million and $1.6 million as of September 30, 2019 and December 31, 2018, respectively.


⁽²⁾	Deferred debt issuance costs are being amortized by the effective interest rate method over the lives of the related debt instruments. These amounts are net of accumulated amortization of $27.7 million and $23.5 million at September 30, 2019 and December 31, 2018, respectively.


⁽³⁾	In the first quarter of 2019, the Company reclassified its TexStar finance lease obligation from debt to other current liabilities on the condensed consolidated balance sheets. Please see Note 7 - “Commitments and Contingencies” for further information.


⁽⁴⁾	The current portion of long-term debt includes $121.7 million of the remaining 2021 Notes that the Company redeemed on October 21, 2019 with cash on hand, after the application of the net proceeds of the 2025 Notes and the $99.5 million borrowing on the expanded credit facility borrowing base. Please see Note 15 - “Subsequent Events” for further information.

6.50% Senior Notes due 2021 (the “2021 Notes”)

During the three months ended September 30, 2019, the Company repurchased $49.0 million aggregate principal amount of its 2021 Notes at an average price of 99.4% of par value, plus accrued and unpaid interest thereon up to, but not including the respective transaction dates. In conjunction with the repurchases during the three months ended September 30, 2019, the Company recorded no gain or loss from debt extinguishment.

As of September 30, 2019, the Company had repurchased $138.8 million aggregate principal amount of its 2021 Notes and the remaining principal amount following these repurchases was $761.2 million. During the nine months ended September 30, 2019, the Company recorded a net gain from debt extinguishment of $0.7 million.

On September 20, 2019, the Company announced a conditional redemption of its 2021 Notes at a price of par, plus accrued and unpaid interest. The obligation to redeem the 2021 Notes was conditioned upon, on or before the redemption date of October 21, 2019, the completion of an offering of at least $550.0 million principal amount of Calumet’s senior debt securities and the satisfaction of all conditions precedent to the effectiveness of the amendment to the Company’s revolving credit facility credit agreement, dated as of September 4, 2019. As of September 30, 2019, the conditions for the redemption of the 2021 Notes had not been met. The conditions for the redemption were met on October 11, 2019, and on October 21, 2019, the Company completed the redemption of the remaining balance of its 2021 Notes, plus accrued and unpaid interest. The redemption was funded with the $540.0 million net proceeds of the offering of 11.00% Senior Notes due 2025 (the “2025 Notes”), the proceeds of a $99.5 million revolving credit facility loan, and $121.7 million of cash on hand. The portion of principal that was redeemed with cash on hand has been classified as a current portion of long-term debt on the balance sheet. Please see Note 15 - “Subsequent Events” for further information.

2021 Notes, 7.625% Senior Notes due 2022 (the “2022 Notes”) and 7.75% Senior Notes due 2023 (the “2023 Notes”)

In accordance with SEC Rule 3-10 of Regulation S-X, unaudited condensed consolidated financial statements of non-guarantors are not required. The Company has no assets or operations independent of its subsidiaries. Obligations under its 2021, 2022 and 2023 Notes are fully and unconditionally and jointly and severally guaranteed on a senior unsecured basis by the Company’s current 100%-owned operating subsidiaries and certain of the Company’s future operating subsidiaries, with the exception of certain 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.

On September 27, 2019, the Company executed supplemental indentures to the indentures governing the 2021, 2022 and 2023 Notes, naming its wholly-owned subsidiaries Calumet Mexico, LLC, Calumet Specialty Oils de Mexico, S. de R.L. de C.V., and Calumet Specialty Products Canada, ULC as additional Guarantors (as defined in the indentures). Following the execution of these supplemental indentures, the Company no longer has material subsidiaries that do not guarantee the 2021, 2022 and 2023 Notes.

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The indentures governing the 2021, 2022 and 2023 Notes contain covenants that, among other things, restrict the Company’s ability and the ability of certain of the Company’s subsidiaries to: (i) sell assets; (ii) pay distributions on, redeem or repurchase the Company’s common units or redeem or repurchase its subordinated debt; (iii) make investments; (iv) incur or guarantee additional indebtedness or issue preferred units; (v) create or incur certain liens; (vi) enter into agreements that restrict distributions or other payments from the Company’s restricted subsidiaries to the Company; (vii) consolidate, merge or transfer all or substantially all of the Company’s assets; (viii) engage in transactions with affiliates and (ix) create unrestricted subsidiaries. These covenants are subject to important exceptions and qualifications. At any time when the 2021, 2022 and 2023 Notes are rated investment grade by either Moody’s Investors Service, Inc. (“Moody’s”) or S&P Global Ratings (“S&P”) and no Default or Event of Default, each as defined in the indentures governing the 2021, 2022 and 2023 Notes, has occurred and is continuing, many of these covenants will be suspended. As of September 30, 2019, the Company’s Fixed Charge Coverage Ratio (as defined in the indentures governing the 2021, 2022 and 2023 Notes) was 2.3. As of September 30, 2019, the Company was in compliance with all covenants under the indentures governing the 2021, 2022 and 2023 Notes.

Third Amended and Restated Senior Secured Revolving Credit Facility

On February 23, 2018, the Company entered into the Third Amended and Restated Credit Agreement (the “Credit Agreement”) governing its senior secured revolving credit facility maturing in February 2023, which provides maximum availability of credit under the revolving credit facility of $600.0 million, subject to borrowing base limitations, and includes a $500.0 million incremental uncommitted expansion feature. The revolving credit facility includes a $25.0 million senior secured first loaned in and last to be repaid out (“FILO”) revolving credit facility limited by a FILO borrowing base calculation. The FILO commitment reduces ratably each quarter starting in November 2019 and ending in August 2020. The reductions in FILO commitments convert to revolving credit facility base commitments over the same period. Lenders under the revolving credit facility have a first priority lien on, among other things, the Company’s accounts receivable and inventory and substantially all of its cash.

On September 4, 2019, the Company entered into the First Amendment to the Credit Agreement. The amendment expands the borrowing base by $99.6 million on the Effective Date (as defined in the amendment) by adding the fixed assets of the Company’s Great Falls, MT refinery as collateral to the borrowing base. The $99.6 million expansion amortizes to zero on a straight-line basis over ten quarters starting in the first quarter of 2020. Additionally, while the fixed assets of the Great Falls, MT refinery are included in the borrowing base, the first amendment provides for a 25 basis points increase in the applicable margin for loans, as well as increases in the minimum availability under the revolving credit facility required for the Company to be able to perform certain actions, including to make restricted payments of other distributions, sell or dispose of certain assets, make acquisitions or investments, or prepay other indebtedness. Among other conditions precedent that were required to be satisfied before the Effective Date, the Company was required to consummate an offering of at least $450.0 million aggregate principal amount of senior unsecured notes. The conditions precedent were not satisfied until October 11, 2019. Therefore, the $99.6 million expansion was not in effect as of September 30, 2019. See Note 15 - “Subsequent Events” for further information.

The revolving credit facility, which is the Company’s primary source of liquidity for cash needs in excess of cash generated from operations, matures in February 2023 and bears interest at a rate equal to prime plus an applicable margin or LIBOR plus an applicable margin, at the Company’s option. The margin can fluctuate quarterly based on the Company’s average availability for additional borrowings under the revolving credit facility in the preceding calendar quarter as follows:



	Base Loans		FILO Loans
Quarterly Average Availability Percentage	Prime Rate Margin	LIBOR Rate Margin	Prime Rate Margin	LIBOR Rate Margin
≥ 66%	0.50%	1.50%	1.50%	2.50%
≥ 33% and < 66%	0.75%	1.75%	1.75%	2.75%
< 33%	1.00%	2.00%	2.00%	3.00%

The credit agreement provides for a 25 basis point reduction in the applicable margin rates beginning in the quarter after our Leverage Ratio (as defined in the credit agreement) is less than 5.5 to 1.0. As the Company met this test in fiscal quarter ended June 30, 2019, its applicable margin for the quarter ended, and including, September 30, 2019 was 25 basis points for prime, 125 basis points for LIBOR, 125 basis points for prime rate based FILO loans and 225 basis points for LIBOR based FILO loans. The margin can fluctuate quarterly based on our average availability for additional borrowings under the revolving credit facility in the preceding calendar quarter. Following the October 11, 2019 Effective Date of the first amendment to the credit agreement, the applicable margin rates are increased by 25 basis points for as long as the Great Falls, MT refinery assets are contributing to the borrowing base. Letters of credit issued under the revolving credit facility accrue fees at a rate equal to the margin (measured in basis points) applicable to LIBOR revolver loans.

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

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preceding month. The Company also pays a customary letter of credit fee, including a fronting fee of 0.125% per annum of the stated amount of each outstanding letter of credit, and customary agency fees.

The revolving credit facility contains various covenants that limit, among other things, the Company’s ability to: incur indebtedness; grant liens; dispose of certain assets; make certain acquisitions and investments; redeem or prepay other debt or make other restricted payments such as distributions to unitholders; enter into transactions with affiliates; and enter into a merger, consolidation or sale of assets. Further, the revolving credit facility contains one springing financial covenant which provides that only if the Company’s availability to borrow loans under the revolving credit facility falls below the sum of the greater of (i) 10% of the borrowing base then in effect, or 15% while the Great Falls, MT refinery is included in the borrowing base, and (ii) $35.0 million (which amount is subject to increase in proportion to revolving commitment increases), plus the amount of FILO Loans outstanding, 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 facility agreement) of at least 1.0 to 1.0. As of September 30, 2019, the Company was in compliance with all covenants under the revolving credit facility.

Maturities of Long-Term Debt

As of September 30, 2019, principal payments on debt obligations and future minimum rentals on finance lease obligations are as follows (in millions):



Year	Maturity
2019	$	122.1
2020	1.8
2021	642.1
2022	350.3
2023	325.4
Thereafter	1.4
Total	$	1,443.1

10. Derivatives

The Company is exposed to price risks due to fluctuations in the price of crude oil, refined products (primarily in the Company’s fuel products segment), natural gas and precious metals. The Company uses various strategies to reduce its exposure to commodity price risk. The strategies to reduce the Company’s risk utilize both physical forward contracts and financially settled derivative instruments, such as swaps, collars, options and futures, to attempt to reduce the Company’s exposure with respect to:


•	crude oil purchases and sales;


•	fuel product sales and purchases;


•	natural gas purchases;


•	precious metals purchases; and


•	fluctuations in the value of crude oil between geographic regions and between the different types of crude oil such as New York Mercantile Exchange West Texas Intermediate (“NYMEX WTI”), Light Louisiana Sweet, Western Canadian Select (“WCS”), WTI Midland, Mixed Sweet Blend and ICE Brent.

The Company manages its exposure to commodity markets, credit, volumetric and liquidity risks to manage its costs and volatility of cash flows as conditions warrant or opportunities become available. These risks may be managed in a variety of ways that may include the use of derivative instruments. Derivative instruments may be used for the purpose of mitigating risks associated with an asset, liability and anticipated future transactions and the changes in fair value of the Company’s derivative instruments will affect its earnings and cash flows; however, such changes should be offset by price or rate changes related to the underlying commodity or financial transaction that is part of the risk management strategy. The Company does not speculate with derivative instruments or other contractual arrangements that are not associated with its business objectives. Speculation is defined as increasing the Company’s natural position above the maximum position of its physical assets or trading in commodities, currencies or other risk bearing assets that are not associated with the Company’s business activities and objectives. The Company’s positions are monitored routinely by a risk management committee to ensure compliance with its stated risk management policy and documented risk management strategies. All strategies are reviewed on an ongoing basis by the Company’s risk management committee, which will add, remove or revise strategies in anticipation of changes in market conditions and/or its risk profiles. Such changes in strategies are to position the Company in relation to its risk exposures in an attempt to capture market opportunities as they arise.

The Company is obligated to repurchase crude oil and refined products from Macquarie at the termination of the Supply and Offtake Agreements in certain scenarios. The Company has determined that the redemption feature on the initially recognized liability related to the Supply and Offtake Agreements is an embedded derivative indexed to commodity prices. As such, the Company has

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accounted for these embedded derivatives at fair value with changes in the fair value, if any, recorded in gain (loss) on derivative instruments in the Company’s unaudited condensed consolidated statements of operations.

The Company recognizes all derivative instruments at their fair values (see Note 11 - “Fair Value Measurements”) 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 in accordance with the provisions of our master netting arrangements.

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 (in millions):



		September 30, 2019							December 31, 2018
	Balance Sheet Location	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Condensed Consolidated Balance Sheets			Net Amounts of Assets Presented in the Condensed Consolidated Balance Sheets		Gross Amounts of Recognized Assets		Gross Amounts Offset in the Condensed Consolidated Balance Sheets			Net Amounts of Assets Presented in the Condensed Consolidated Balance Sheets
Derivative instruments not designated as hedges:
Specialty products segment:
Midland crude oil basis swaps	Derivative assets	$	—	$	—		$	—	$	1.0	$	—		$	1.0
Fuel products segment:
Inventory financing obligation	Obligations under inventory financing agreements	$	1.5	$	(1.5	)	$	—	$	1.5	$	—		$	1.5
WCS crude oil basis swaps	Derivative assets	—		—			—		16.5		(1.6		)	14.9
WCS crude oil percentage basis swaps	Derivative assets	2.4		(2.4		)	—		—		(6.1		)	(6.1		)
Midland crude oil basis swaps	Derivative assets	—		—			—		7.1		—			7.1
Gasoline crack spread swaps	Derivative assets	0.2		(0.1		)	0.1		—		—			—
Diesel crack spread swap	Derivative assets	0.2		—			0.2		7.4		—			7.4
Diesel percentage basis crack spread swap	Derivative assets	1.2		(1.0		)	0.2		—		(6.0		)	(6.0		)
2/1/1 Crack spread swap	Derivative assets	0.3		—			0.3		—		—			—
Total derivative instruments		$	5.8	$	(5.0	)	$	0.8	$	33.5	$	(13.7	)	$	19.8

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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 (in millions):



		September 30, 2019								December 31, 2018
	Balance Sheet Location	Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Condensed Consolidated Balance Sheets		Net Amounts of Liabilities Presented in the Condensed Consolidated Balance Sheets			Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Condensed Consolidated Balance Sheets		Net Amounts of Liabilities Presented in the Condensed Consolidated Balance Sheets
Derivative instruments not designated as hedges:
Fuel products segment:
Inventory financing obligation	Obligations under inventory financing agreements	$	(2.7	)	$	1.5	(1.2		)	$	—		$	—	$	—
WCS crude oil basis swaps	Derivative liabilities	—			—		—			(1.6		)	1.6		—
WCS crude oil percentage basis swaps	Derivative liabilities	(2.4		)	2.4		—			(6.1		)	6.1		—
Gasoline crack spread swaps	Derivative liabilities	(0.1		)	0.1		—			—			—		—
Diesel percentage basis crack spread swaps	Derivative liabilities	(1.0		)	1.0		—			(6.0		)	6.0		—
Total derivative instruments		$	(6.2	)	$	5.0	$	(1.2	)	$	(13.7	)	$	13.7	$	—

The Company is exposed to credit risk in the event of nonperformance by its counterparties on these derivative transactions. The Company does not expect nonperformance on any derivative instruments, however, no assurances can be provided. The Company’s credit exposure related to these derivative instruments is represented by the fair value of contracts reported as derivative assets. As of September 30, 2019, the Company had three counterparties in which the derivatives held were in net assets totaling $0.8 million. As of December 31, 2018, the Company had four 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 A3 and BBB+ by Moody’s and S&P, respectively. In the event of default, the Company would potentially be subject to losses on derivative instruments with mark-to-market gains. The Company requires collateral from its counterparties when the fair value of the derivatives exceeds agreed-upon thresholds in its master derivative contracts with these counterparties. No such collateral was held by the Company as of September 30, 2019 or December 31, 2018. Collateral received from counterparties is reported in other current liabilities, and collateral held by counterparties is reported in prepaid expenses and other current assets on the Company’s condensed consolidated balance sheets and is not netted against derivative assets or liabilities.

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. Any outstanding collateral is released to the Company upon settlement of the related derivative instrument liability. As of September 30, 2019 and December 31, 2018, the Company had provided no collateral to its counterparties.

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 Not Designated as Hedges

For derivative instruments not designated as hedges, the change in fair value of the asset or liability for the period is recorded to gain (loss) on derivative instruments in the unaudited condensed consolidated statements of operations. Upon the settlement of a derivative not designated as a hedge, the gain or loss at settlement is recorded to gain (loss) on derivative instruments in the unaudited condensed consolidated statements of operations. The Company has entered into gasoline swaps, diesel swaps and certain crude oil

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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. However, these instruments provide economic hedges of the purchases and sales of the Company’s crude oil, gasoline and diesel.

The Company recorded the following gains (losses) in its unaudited condensed consolidated statements of operations, related to its derivative instruments not designated as hedges (in millions):



Type of Derivative	Amount of Realized Gain (Loss) Recognized in Gain (Loss) on Derivative Instruments					Amount of Unrealized Gain (Loss) Recognized in Gain (Loss) on Derivative Instruments
	Three Months Ended September 30,					Three Months Ended September 30,
	2019		2018			2019			2018
Fuel products segment:
Inventory financing obligation	—		—			(5.5		)	(9.4		)
WCS crude oil basis swaps	—		0.4			—			(3.4		)
WCS crude oil percentage basis swaps	0.1		—			(0.3		)	(4.1		)
Midland crude oil basis swaps	—		(1.2		)	—			10.1
Gasoline swaps	—		—			0.1			—
2/1/1 Crack spread swaps	—		—			0.3			—
Diesel crack spread swaps	0.3		0.5			0.2			(0.8		)
Diesel percentage basis crack spread swaps	—		—			(0.2		)	5.2
Total	$	0.4	$	(0.3	)	$	(5.4	)	$	(2.4	)

The Company recorded the following gains (losses) in its unaudited condensed consolidated statements of operations for the nine months ended September 30, 2019 and 2018, related to its derivative instruments not designated as hedges (in millions):



Type of Derivative	Amount of Realized Gain (Loss) Recognized in Gain (Loss) on Derivative Instruments						Amount of Unrealized Gain (Loss) Recognized in Gain (Loss) on Derivative Instruments
	Nine Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
Specialty products segment:
Midland crude oil basis swaps	1.6			—			(1.0		)	—
Fuel products segment:
Inventory financing obligation	—			—			(2.7		)	(16.3		)
Crude oil swaps	—			—			—			(0.3		)
WCS crude oil basis swaps	17.1			0.4			(14.9		)	(2.8		)
WCS crude oil percentage basis swaps	1.0			—			6.0			(4.9		)
Midland crude oil basis swaps	9.0			(1.2		)	(7.1		)	13.0
Gasoline swaps	—			—			0.1			0.2
Gasoline crack spread swaps	—			(1.0		)	—			1.8
2/1/1 Crack spread swaps	—			—			0.3			—
Diesel swaps	—			—			—			0.2
Diesel crack spread swaps	6.4			(0.6		)	(7.2		)	5.1
Diesel percentage basis crack spread swaps	(0.5		)	—			6.3			4.4
Total	$	34.6		$	(2.4	)	$	(20.2	)	$	0.4

Derivative Positions

WCS Crude Oil Basis Swap Contracts

The Company has entered into crude oil basis swaps to mitigate the risk of future changes in pricing differentials between WCS and NYMEX WTI. At September 30, 2019, the Company had no derivatives related to either WCS crude oil basis purchases or sales in its fuel products segment, as all positions outstanding at December 31, 2018 were settled during 2019.

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At December 31, 2018, the Company had the following derivatives related to WCS crude oil basis purchases in its fuel products segment, none of which are designated as hedges:



WCS Crude Oil Basis Swap Contracts by Expiration Dates	Barrels Purchased	BPD	Average Differential to NYMEX WTI ($/Bbl)
First Quarter 2019	419,000	4,656	$	(28.10	)
Second Quarter 2019	455,000	5,000	$	(28.22	)
Third Quarter 2019	460,000	5,000	$	(28.22	)
Fourth Quarter 2019	460,000	5,000	$	(28.22	)
Total	1,794,000
Average price			$	(28.19	)

At December 31, 2018, the Company had the following derivatives related to WCS crude oil basis sales in its fuel products segment, none of which are designated as hedges:



WCS Crude Oil Basis Swap Contracts by Expiration Dates	Barrels Sold	BPD	Average Differential to NYMEX WTI ($/Bbl)
First Quarter 2019	388,000	4,311	$	(19.84	)
Second Quarter 2019	455,000	5,000	$	(19.84	)
Third Quarter 2019	460,000	5,000	$	(19.84	)
Fourth Quarter 2019	460,000	5,000	$	(19.84	)
Total	1,763,000
Average price			$	(19.84	)

WCS Crude Oil Percentage Basis Swap Contracts

The Company has entered into derivative instruments to secure a percentage differential of WCS crude oil to NYMEX WTI. At September 30, 2019, the Company had the following derivatives related to crude oil percentage basis swap purchases in its fuel products segment, none of which are designated as hedges:



WCS Crude Oil Percentage Basis Swap Contracts by Expiration Dates	Barrels Purchased	BPD	Fixed Percentage of NYMEX WTI (Average % of WTI/Bbl)
Fourth Quarter 2019	460,000	5,000	66.32	%
Total	460,000
Average percentage			66.32	%

At September 30, 2019, the Company had the following derivatives related to crude oil percentage basis swap sales in its fuel products segment, none of which are designated as hedges:



WCS Crude Oil Percentage Basis Swap Contracts by Expiration Dates	Barrels Sold	BPD	Fixed Percentage of NYMEX WTI (Average % of WTI/Bbl)
Fourth Quarter 2019	460,000	5,000	66.16	%
Total	460,000
Average percentage			66.16	%

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At December 31, 2018, the Company had the following derivatives related to crude oil percentage basis swap purchases in its fuel products segment, none of which are designated as hedges:



WCS Crude Oil Percentage Basis Swap Contracts by Expiration Dates	Barrels Purchased	BPD	Fixed Percentage of NYMEX WTI (Average % of WTI/Bbl)
First Quarter 2019	450,000	5,000	66.32	%
Second Quarter 2019	455,000	5,000	66.32	%
Third Quarter 2019	460,000	5,000	66.32	%
Fourth Quarter 2019	460,000	5,000	66.32	%
Total	1,825,000
Average percentage			66.32	%

At December 31, 2018, the Company had no derivatives related to crude oil percentage basis swap sales in its fuel products segment.

Midland Crude Oil Basis Swap Contracts

The Company had no crude oil basis swaps to mitigate the risk of future changes in pricing differentials between WTI Midland and NYMEX WTI as of September 30, 2019.

At December 31, 2018, the Company had the following derivatives related to Midland crude oil basis swaps in its fuel products segment, none of which are designated as hedges:



Midland Crude Oil Basis Swap Contracts by Expiration Dates	Barrels Purchased	BPD	Average Differential to NYMEX WTI ($/Bbl)
First Quarter 2019	501,500	5,572	$	(12.79	)
Second Quarter 2019	773,500	8,500	$	(11.74	)
Total	1,275,000
Average price			$	(12.27	)

Diesel Crack Spread Swap Contracts

At September 30, 2019, the Company had the following derivatives related to diesel crack spread sales in its fuel products segment, none of which are designated as hedges:



Diesel Crack Spread Swap Contracts by Expiration Dates	Barrels Sold	BPD	Average Swap ($/Bbl)
Fourth Quarter 2019	62,000	674	$	22.18
First Quarter 2020	136,500	1,500	$	22.91
Second Quarter 2020	60,000	659	$	23.10
Total	258,500
Average price			$	22.78

At December 31, 2018, the Company had the following derivatives related to diesel crack spread sales in its fuel products segment, none of which are designated as hedges:



Diesel Crack Spread Swap Contracts by Expiration Dates	Barrels Sold	BPD	Average Swap ($/Bbl)
First Quarter 2019	450,000	5,000	$	25.58
Second Quarter 2019	455,000	5,000	$	25.58
Third Quarter 2019	460,000	5,000	$	25.58
Fourth Quarter 2019	460,000	5,000	$	25.58
Total	1,825,000
Average price			$	25.58

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Diesel Percentage Basis Crack Spread Swap Contracts

The Company has entered into diesel crack spread derivative instruments to secure a fixed percentage of gross profit on diesel in excess of the floating value of NYMEX WTI crude oil. At September 30, 2019, the Company had the following derivatives related to diesel percent basis crack spread swap sales 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 (Average % of WTI/Bbl)
Fourth Quarter 2019	460,000	5,000	138.38	%
Total	460,000
Average percentage			138.38	%

At September 30, 2019, the Company had the following derivatives related to diesel percentage basis swap purchases in its fuel products segment, none of which are designated as hedges:



Diesel Percentage Basis Crack Spread Swap Contracts by Expiration Dates	Barrels Purchased	BPD	Fixed Percentage of NYMEX WTI (Average % of WTI/Bbl)
Fourth Quarter 2019	460,000	5,000	137.37	%
Total	460,000
Average percentage			137.37	%

At December 31, 2018, the Company had the following derivatives related to diesel percent basis crack spread swap sales and no derivatives related to diesel percent basis crack spread swap purchases 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 (Average % of WTI/Bbl)
First Quarter 2019	450,000	5,000	138.38	%
Second Quarter 2019	455,000	5,000	138.38	%
Third Quarter 2019	460,000	5,000	138.38	%
Fourth Quarter 2019	460,000	5,000	138.38	%
Total	1,825,000
Average percentage			138.38	%

Gasoline Crack Spread Swap Contracts

At September 30, 2019, the Company had the following derivatives related to gasoline crack spread sales in its fuel products segment, none of which are designated as hedges:



Gasoline Crack Spread Swap Contracts by Expiration Dates	Barrels Sold	BPD	Average Swap ($/Bbl)
Fourth Quarter 2019	62,000	674	$	9.37
First Quarter 2020	136,500	1,500	$	11.69
Second Quarter 2020	60,000	659	$	16.48
Total	258,500
Average price			$	12.25

At December 31, 2018, the Company had no derivatives related to gasoline crack spread sales in its fuel products segment.

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2/1/1 Crack Spread Swap Contracts

At September 30, 2019, the Company had the following derivatives related to 2/1/1 crack spread sales in its fuel products segment, none of which are designated as hedges:



2/1/1 Crack Spread Swap Contracts by Expiration Dates	Barrels Sold	BPD	Average Swap ($/Bbl)
Fourth Quarter 2019	31,000	337	$	15.88
First Quarter 2020	182,000	2,000	$	17.43
Second Quarter 2020	15,000	165	$	19.50
Total	228,000
Average price			$	17.35

At December 31, 2018, the Company had no derivatives related to 2/1/1 crack spread sales in its fuel products segment.

11. Fair Value Measurements

In accordance with ASC 820, 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 contracts, which are not traded on a public exchange. Substantially all of the Company’s derivative instruments are with counterparties that have long-term credit ratings of at least A3 and BBB+ by Moody’s and S&P, respectively.

Commodity derivative instruments are measured at fair value using a market approach. To estimate the fair values of the Company’s commodity derivative instruments, the Company uses the forward rate, the strike price, contractual notional amounts, the risk-free rate of return and contract maturity. Various analytical tests are performed to validate the counterparty data. The fair values of the Company’s derivative instruments are adjusted for nonperformance risk and creditworthiness of the counterparty through the Company’s credit valuation adjustment (“CVA”). The CVA is calculated at the counterparty level utilizing the fair value exposure at each payment date and applying a weighted probability of the appropriate survival and marginal default percentages. The Company uses the counterparty’s marginal default rate and the Company’s survival rate when the Company is in a net asset position at the payment date and uses the Company’s marginal default rate and the counterparty’s survival rate when the Company is in a net liability position at the payment date. As a result of applying the applicable CVA at September 30, 2019 and December 31, 2018, the Company’s net assets and net liabilities changed, in each case, by an immaterial amount.

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 counterparties and unobservable inputs in the forward rate, the Company has categorized these derivative instruments as Level 3. Significant increases (decreases) in any of those unobservable inputs in isolation would result in a significantly lower (higher) fair value measurement. The Company believes it has obtained the most accurate information available for the types of derivative instruments it holds. See Note 10 - “Derivatives” for further information on derivative instruments.

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Pension Assets

Pension assets are reported at fair value in the accompanying unaudited condensed consolidated financial statements. At September 30, 2019, the Company’s investments associated with its pension plan primarily consisted of mutual funds. The mutual funds are valued at the net asset value of shares in each fund held by the Pension Plan at quarter end as provided by the respective investment sponsors or investment advisers. Plan investments can be redeemed within a short time frame (approximately ten business days), if requested.

Liability Awards

Unit based compensation liability awards are awards that are expected to be settled in cash on their vesting dates, rather than in equity units (“Liability Awards”). The Liability Awards are categorized as Level 1 because the fair value of the Liability Awards is based on the Company’s quoted closing unit price as of each balance sheet date.

Renewable Identification Numbers Obligation

The Company’s RINs Obligation is categorized as Level 2 and is measured at fair value using the market approach based on quoted prices from an independent pricing service. See Note 7 - “Commitments and Contingencies” for further information on the Company’s RINs Obligation.

Hierarchy of Recurring Fair Value Measurements

The Company’s recurring assets and liabilities measured at fair value were as follows (in millions):



	September 30, 2019												December 31, 2018
	Level 1			Level 2			Level 3			Total			Level 1			Level 2			Level 3			Total
Assets:
Derivative assets:
Gasoline crack spread swaps	$	—		$	—		$	0.1		$	0.1		$	—		$	—		$	—		$	—
Inventory financing obligation	—			—			—			—			—			—			1.5			1.5
Diesel crack spread swaps	—			—			0.2			0.2			—			—			7.4			7.4
Diesel percentage basis crack spread swaps	—			—			0.2			0.2			—			—			(6.0		)	(6.0		)
2/1/1 Crack spread swap	—			—			0.3			0.3			—			—			—			—
WCS crude oil basis swaps	—			—			—			—			—			—			14.9			14.9
WCS crude oil percentage basis swaps	—			—			—			—			—			—			(6.1		)	(6.1		)
Midland crude oil basis swaps	—			—			—			—			—			—			8.1			8.1
Total derivative assets	$	—		$	—		$	0.8		$	0.8		$	—		$	—		$	19.8		$	19.8
Pension plan investments	—			—			—			—			0.1			—			—			0.1
Total recurring assets at fair value	$	—		$	—		$	0.8		$	0.8		$	0.1		$	—		$	19.8		$	19.9
Liabilities:
Derivative liabilities:
Inventory financing obligation	$	—		$	—		$	(1.2	)	$	(1.2	)	$	—		$	—		$	—		$	—
Total derivative liabilities	—			—			(1.2		)	(1.2		)	—			—			—			—
RINs Obligation	—			(14.4		)	—			(14.4		)	—			(15.8		)	—			(15.8		)
Liability Awards	(6.8		)	—			—			(6.8		)	(2.7		)	—			—			(2.7		)
Total recurring liabilities at fair value	$	(6.8	)	$	(14.4	)	$	(1.2	)	$	(22.4	)	$	(2.7	)	$	(15.8	)	$	—		$	(18.5	)

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The table below sets forth a summary of net changes in fair value of the Company’s Level 3 financial assets and liabilities (in millions):



	Nine Months Ended September 30,
	2019			2018
Fair value at January 1,	$	19.8		$	(10.4	)
Realized (gain) loss on derivative instruments	(34.6		)	2.4
Unrealized gain (loss) on derivative instruments	(20.2		)	0.4
Settlements	34.6			(2.4		)
Fair value at September 30,	$	(0.4	)	$	(10.0	)
Total gain (loss) included in net loss attributable to changes in unrealized gain (loss) relating to financial assets and liabilities held as of September 30,	$	(20.2	)	$	0.4

All settlements from derivative instruments not designated as hedges are recorded in gain (loss) on derivative instruments in the unaudited condensed consolidated statements of operations. See Note 10 - “Derivatives” for further information on derivative instruments.

Nonrecurring Fair Value Measurements

Certain non-financial 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 definite-lived intangible assets and property, plant and equipment, when events or circumstances warrant such a review. Fair value is determined primarily using anticipated cash flows assumed by a market participant discounted at a rate commensurate with the risk involved and these assets would generally be classified within Level 3, the Company was required to measure and record such assets at fair value within its unaudited condensed consolidated financial statements.

The Company’s investment in FHC is a non-marketable equity security without a readily determinable fair value. The Company records this investment using a measurement alternative which measures the security at cost minus impairment, if any, plus or minus changes resulting from qualifying observable price changes with a same or similar security from the same issuer. The investment in FHC is recorded at fair value only if an impairment or observable price adjustment is recognized in the current period. If an observable price adjustment or impairment is recognized, the Company would classify this asset as Level 3 within the fair value hierarchy based on the nature of the fair value inputs. During the three and nine months ended September 30, 2019, the Company recorded impairment on the investment in FHC and the categorization of the framework used to value the assets is considered Level 3. See Note 6 - “Investment in Unconsolidated Affiliates” for further information.

Estimated Fair Value of Financial Instruments

Cash and cash equivalents

The carrying value of cash and cash equivalents is each considered to be representative of its fair value.

Debt

The estimated fair value of long-term debt at September 30, 2019 and December 31, 2018, consists primarily of senior notes. The estimated aggregate fair value of the Company’s senior notes defined as Level 1 was based upon quoted market prices in an active market. The carrying value of borrowings, if any, under the Company’s revolving credit facility, finance lease obligations and other obligations approximate their fair values as determined by discounted cash flows and are classified as Level 3. See Note 9 - “Long-Term Debt” for further information on long-term debt.

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The Company’s carrying and estimated fair value of the Company’s financial instruments, carried at adjusted historical cost were as follows (in millions):



		September 30, 2019				December 31, 2018
	Level	Fair Value		Carrying Value		Fair Value		Carrying Value
Financial Instrument:
Senior notes	1	$	1,400.4	$	1,425.9	$	1,287.4	$	1,560.7
Finance lease and other obligations	3	$	6.9	$	6.9	$	47.6	$	47.6

12. Earnings Per Unit

The following table sets forth the computation of basic and diluted earnings per limited partner unit (in millions, except unit and per unit data):



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
Numerator for basic and diluted earnings per limited partner unit:
Net loss from continuing operations	$	(4.6	)	$	(16.0	)	$	(5.0	)	$	(70.1	)
Less:
General partner’s interest in net loss from continuing operations	(0.1		)	(0.3		)	(0.1		)	(1.4		)
Net loss from continuing operations available to limited partners	$	(4.5	)	$	(15.7	)	$	(4.9	)	$	(68.7	)
Net loss from discontinued operations available to limited partners	—			(0.4		)	—			(3.0		)
Net loss available to limited partners	$	(4.5	)	$	(16.1	)	$	(4.9	)	$	(71.7	)

Denominator for basic and diluted earnings per limited partner unit:
Weighted average limited partner units outstanding⁽¹⁾	78,299,472			77,783,879			78,174,976			77,643,006
Limited partners’ interest basic and diluted net loss per unit:
From continuing operations	$	(0.06	)	$	(0.20	)	$	(0.06	)	$	(0.88	)
From discontinued operations	—			(0.01		)	—			(0.04		)
Limited partners’ interest	$	(0.06	)	$	(0.21	)	$	(0.06	)	$	(0.92	)


⁽¹⁾	Total diluted weighted average limited partner units outstanding excludes 0.1 million for the three and nine months ended September 30, 2019 and 0.2 million for the three and nine months ended September 30, 2018, consisting of unvested phantom units.

13. Segments and Related Information

a. Segment Reporting

The Company determines its reportable segments based on how the business is managed internally for the products sold to customers, including how results are reviewed and resources are allocated by the chief operating decision makers (“CODM”). The Company’s operations are managed by the CODM using the following reportable segments:

•

Specialty Products. The specialty products segment is the Company’s core business which 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, asphalt and other products which are primarily sold to customers located in the PADD 3 and PADD 4 areas within the U.S.


•	Corporate. The corporate segment primarily consists of general and administrative expenses not allocated to the Specialty Products or Fuel Products segments.

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During the third quarter of 2019, the CODM changed how the Company assesses performance, allocates resources, and allocates certain costs. In response to those changes, a corporate segment was added. Prior to the third quarter of 2019, various pricing models were used in determining the calculation of intersegment sales. Beginning in the third quarter of 2019, all intersegment sales are calculated using market-based transfer pricing. Further, cost allocations were modified to conform to the new segment alignments. This change in management reporting has resulted in an increase in the inter-segment sales reported by the Company’s specialty products operating segment. Prior period amounts have been recast to conform with the current presentation. These changes in management reporting had no impact on consolidated revenue, segment reporting of external sales or consolidated Adjusted EBITDA.

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 2018 Annual Report, except that the disaggregated financial results for the reporting segments have been prepared using a management approach, which is consistent with the basis and manner in which management internally disaggregates financial information for the purposes of assisting internal operating decisions. The Company accounts for intersegment sales and transfers using a market-based approach. The Company evaluates performance based upon Adjusted EBITDA (a non-GAAP financial measure). The Company defines Adjusted EBITDA for any period as EBITDA adjusted for (a) impairment; (b) unrealized gains and losses from mark to market accounting for hedging activities; (c) realized gains and losses under derivative instruments excluded from the determination of net income (loss); (d) 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); (e) debt refinancing fees, premiums and penalties; (f) any net loss realized in connection with an asset sale that was deducted in computing net income (loss) and (g) all extraordinary, unusual or non-recurring items of gain or loss, or revenue or expense.

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.

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Reportable segment information for the three months ended September 30, 2019 and 2018, is as follows (in millions):



Three Months Ended September 30, 2019	Specialty Products		Fuel Products		Corporate			Eliminations			Consolidated Total
Sales:
External customers	$	355.8	$	573.8	$	—		$	—		$	929.6
Intersegment sales	19.8		14.3		—			(34.1		)	—
Total sales	$	375.6	$	588.1	$	—		$	(34.1	)	$	929.6
Adjusted EBITDA	$	52.5	$	44.1	$	(23.1	)	$	—		$	73.5
Reconciling items to net loss:
Depreciation and amortization	12.9		18.6		2.0			—			33.5
Other non-recurring expenses	—		—		—			—			1.3
Unrealized loss on derivatives											5.4
Interest expense											33.8
Loss on impairment and disposal of fixed assets											3.2
Equity based compensation and other items											0.4
Income tax expense											0.5
Net loss from continuing operations											$	(4.6	)


Three Months Ended September 30, 2018	Specialty Products		Fuel Products		Corporate			Eliminations			Consolidated Total
Sales:
External customers	$	349.2	$	604.3	$	—		$	—		$	953.5
Intersegment sales	24.1		20.9		—			(45.0		)	—
Total sales	$	373.3	$	625.2	$	—		$	(45.0	)	$	953.5
Adjusted EBITDA	$	36.6	$	41.9	$	(24.0	)				$	54.5
Reconciling items to net loss:
Depreciation and amortization	12.1		18.1		2.1			—			32.3
Realized loss on derivatives, not reflected in net loss or settled in a prior period	0.1		0.6		—			—			0.7
Unrealized loss on derivatives											2.4
Interest expense											37.7
Equity based compensation and other items											(3.0		)
Income tax expense											0.4
Net loss from continuing operations											$	(16.0	)

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Reportable segment information for the nine months ended September 30, 2019 and 2018, is as follows (in millions):



Nine Months Ended September 30, 2019	Specialty Products			Fuel Products		Corporate			Eliminations			Consolidated Total
Sales:
External customers	$	1,052.4		$	1,625.4	$	—					$	2,677.8
Intersegment sales	67.0			37.7		—			(104.7		)	—
Total sales	$	1,119.4		$	1,663.1	$	—		$	(104.7	)	$	2,677.8
Income from unconsolidated affiliates	$	3.8		$	—							$	3.8
Adjusted EBITDA	$	171.3		$	155.5	$	(76.0	)				$	250.8
Reconciling items to net loss:
Depreciation and amortization	36.6			56.8		5.7						99.1
Other non-recurring expenses	—			—		—						1.3
Gain on sale of unconsolidated affiliate	(1.2		)	—		—						(1.2		)
Unrealized loss on derivatives												20.2
Interest expense												99.2
Gain on debt extinguishment												(0.7		)
Loss on impairment and disposal of fixed assets												31.1
Equity based compensation and other items												6.1
Income tax expense												0.7
Net loss from continuing operations												$	(5.0	)


Nine Months Ended September 30, 2018	Specialty Products			Fuel Products		Corporate			Eliminations			Consolidated Total
Sales:
External customers	$	1,053.6		$	1,595.9	$	—		$	—		$	2,649.5
Intersegment sales	67.8			46.8		—			(114.6		)	—
Total sales	$	1,121.4		$	1,642.7	$	—		$	(114.6	)	$	2,649.5
Loss from unconsolidated affiliates	$	(3.7	)	$	—				$	—		$	(3.7	)
Adjusted EBITDA	$	129.3		$	155.3	$	(74.4	)	$	—		$	210.2
Reconciling items to net loss:
Depreciation and amortization	37.5			53.4		6.6			—			97.5
Realized loss on derivatives, not reflected in net loss or settled in a prior period	0.5			2.3		—			—			2.8
Unrealized gain on derivatives												(0.4		)
Interest expense												120.4
Loss on debt extinguishment												58.8
Equity based compensation and other items												0.2
Income tax expense												1.0
Net loss from continuing operations												$	(70.1	)

b. Geographic Information

International sales accounted for less than 10% of consolidated sales in each of the three and nine months ended September 30, 2019 and 2018. Substantially all of the Company’s long-lived assets are domestically located.

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c. Product Information

The Company offers specialty products primarily in categories consisting of lubricating oils, solvents, waxes, synthetic lubricants and other products. Fuel products categories primarily consist of gasoline, diesel, jet fuel, asphalt and other products. The following table sets forth the major product category sales for each of the Specialty products and Fuel products segments for the three months ended September 30, 2019 and 2018 (dollars in millions):



	Three Months Ended September 30,
	2019				2018
Specialty products:
Lubricating oils	$	156.1	16.8	%	$	146.6	15.4	%
Solvents	86.1		9.3	%	88.3		9.3	%
Waxes	30.1		3.2	%	30.1		3.2	%
Packaged and synthetic specialty products	59.6		6.4	%	64.0		6.6	%
Other	23.9		2.6	%	20.2		2.1	%
Total	$	355.8	38.3	%	$	349.2	36.6	%
Fuel products:
Gasoline	$	189.5	20.4	%	$	191.2	20.1	%
Diesel	225.4		24.2	%	257.5		27.0	%
Jet fuel	39.5		4.2	%	28.1		2.9	%
Asphalt, heavy fuel oils and other	119.4		12.8	%	127.5		13.4	%
Total	$	573.8	61.7	%	$	604.3	63.4	%
Consolidated sales	$	929.6	100.0	%	$	953.5	100.0	%

The following table sets forth the major product category sales for the nine months ended September 30, 2019 and 2018 (dollars in millions):



	Nine Months Ended September 30,
	2019				2018
Specialty products:
Lubricating oils	$	460.7	17.2	%	$	448.3	16.9	%
Solvents	254.2		9.5	%	254.3		9.6	%
Waxes	92.6		3.5	%	87.8		3.3	%
Packaged and synthetic specialty products	180.2		6.7	%	204.9		7.8	%
Other	64.7		2.4	%	58.3		2.2	%
Total	$	1,052.4	39.3	%	$	1,053.6	39.8	%
Fuel products:
Gasoline	$	530.9	19.8	%	$	528.8	20.0	%
Diesel	669.4		25.0	%	681.5		25.7	%
Jet fuel	100.8		3.8	%	78.9		3.0	%
Asphalt, heavy fuel oils and other	324.3		12.1	%	306.7		11.5	%
Total	$	1,625.4	60.7	%	$	1,595.9	60.2	%
Consolidated sales	$	2,677.8	100.0	%	$	2,649.5	100.0	%

d. Major Customers

During the three and nine months ended September 30, 2019 and 2018, the Company had no customer that represented 10% or greater of consolidated sales.

e. Major Suppliers

During the three months ended September 30, 2019 and 2018, the Company had two suppliers that supplied approximately 67.5% and 56.5%, respectively, of its crude oil supply. During the nine months ended September 30, 2019 and 2018, the Company had two suppliers that supplied approximately 64.6% and 58.5%, respectively, of its crude oil supply.

14. Leases

The Company has various operating and finance leases primarily for the use of land, storage tanks, railcars, equipment, precious metals and office facilities that have remaining lease terms of greater than one year to 15 years, some of which include

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options to extend the lease for up to 35 years, and some of which include options to terminate the lease within one year. Effective January 1, 2019, the Company adopted ASU 2016-02 using a modified retrospective transition approach that applied the new standard to all leases existing at the effective date of the standard with no restatement of prior periods. Given the adoption of ASU 2016-02, the Company’s operating leases have been included in operating lease right-of-use (“ROU”) assets, current portion of operating lease liabilities and long-term portion of operating lease liabilities in the condensed consolidated balance sheets. ROU assets represent the Company’s right to use an underlying asset for the lease term and lease liabilities represent its obligation to make lease payments arising from the lease. The Company’s finance leases are included in property, plant and equipment, current portion of long-term debt and long-term debt, less current portion in the condensed consolidated balance sheets, which remains consistent with the Company’s presentation of its finance leases prior to the adoption of ASU 2016-02.

The Company elected to apply the following practical expedients and policy elections provided by the standard at transition:


•	Package of Three - The Company has elected that it will not reassess contracts that have expired or existed at the date of adoption for (1) leases under the new definition of a lease, (2) lease classification, and (3) whether previously capitalized initial direct costs would qualify for capitalization under ASC 842.


•	Portfolio Approach - The Company elected to determine the discount rate used to measure lease liabilities at the portfolio level. Specifically, the Company segregated its leases into different populations based on lease term.

•

Discount Rate - The Company elected to apply the discount rate at transition based on the remaining lease term and lease payments rather than the original lease term and lease payments. As a majority of the Company’s leases do not provide an implicit rate, the Company used an incremental borrowing rate based on information available at the date of transition to determine the present value of lease payments.


•	Lease/Non-Lease Components - The Company elected to not separate non-lease components.


•	Definition of Minimum Rental Payments - The Company elected to include executory costs as part of the minimum lease payments for purposes of measuring the lease liability and right-of-use asset at transition.


•	Land Easement - The Company elected not to assess whether any land easements are, or contain, leases in accordance with ASC 842 when transitioning to the standard.

Supplemental balance sheet information related to the Company’s leases as of September 30, 2019, were as follows (in millions):



		September 30, 2019
Assets:	Classification:
Operating lease assets	Operating lease right-of-use assets ⁽²⁾	$	110.5
Finance lease assets	Property, plant and equipment, net ⁽¹⁾	3.2
Total leased assets		$	113.7
Liabilities:
Current
Operating	Current portion of operating lease liabilities ⁽²⁾	$	62.3
Finance	Current portion of long-term debt	0.3
Non-current
Operating	Long-term operating lease liabilities ⁽²⁾	48.9
Finance	Long term debt, less current portion	2.5
Total lease liabilities		$	114.0


⁽¹⁾	Finance lease assets are recorded net of accumulated amortization of $7.1 million as of September 30, 2019.


⁽²⁾	In the third quarter of 2019, the Company had additions to its operating lease right of use assets and operating lease liabilities of approximately $2.7 million.

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Lease expense for lease payments is recognized on a straight-line basis over the lease term. The components of lease expense related to the Company’s leases for the three and nine months ended September 30, 2019 were as follows (in millions).



		Three Months Ended		Nine Months Ended
Lease Costs:	Classification:	September 30, 2019
Fixed operating lease cost	Cost of Sales; SG&A Expenses	$	16.7	$	50.4
Short-term operating lease cost ⁽¹⁾	Cost of Sales; SG&A Expenses	2.2		5.6
Variable operating lease cost ^{(2) (3)}	Cost of Sales; SG&A Expenses	0.4		1.1
Finance lease cost:
Amortization of right-of-use asset	Cost of Sales	0.4		1.1
Interest on lease liabilities	Interest expense	0.2		1.3
Total lease cost		$	19.9	$	59.5


⁽¹⁾	The Company’s leases with an initial term of 12 months or less are not recorded on the condensed consolidated balance sheets.

⁽²⁾

Approximately $0.5 million of the Company’s variable operating lease cost for the nine months ended September 30, 2019 relates to its lease agreement with Phillips 66 related to the LVT unit at its Lake Charles, Louisiana refinery (“the LVT Agreement”). Pursuant to the LVT Agreement, Phillips 66 is obligated to supply a minimum supply quantity which the Company agrees to purchase through December 31, 2020. Pricing for the agreement is indexed to the prior month’s average of Platts Mid USGC 55 Grade Jet Kero price on the day of loading plus an adder. Phillips 66 invoices the Company for the estimated volume of product to be purchased by the Company based on a supplied forecast and differences between actual volumes purchased and the estimated volume of product originally billed makes up the variable component of the operating lease contract. There were no variable operating lease costs related the LVT Agreement for the three months ended September 30, 2019


⁽³⁾	The Company’s railcar leases typically include a mileage limit the railcar can travel over the life of the lease. For any mileage incurred over this limit, the Company is obligated to pay an agreed upon dollar value for each mile that is traveled over the limit.

As of September 30, 2019, the Company had estimated minimum commitments for the payment of rentals under leases which, at inception, had a noncancelable term of more than one year, as follows (in millions):



Maturity of Lease Liabilities	Operating Leases ⁽¹⁾		Finance Leases ⁽²⁾		Total
2019	$	17.3	$	0.1	$	17.4
2020	65.8		0.5		66.3
2021	14.6		0.5		15.1
2022	10.3		0.5		10.8
2023	6.9		0.5		7.4
Thereafter	7.2		1.6		8.8
Total	$	122.1	$	3.7	$	125.8
Less: Interest	10.9		0.9		11.8
Present value of lease liabilities	$	111.2	$	2.8	$	114.0


⁽¹⁾	As of September 30, 2019, the Company’s operating lease payments included no material options to extend lease terms that are reasonably certain of being exercised. The Company has no legally binding minimum lease payments for leases signed but not yet commenced as of September 30, 2019.


⁽²⁾	As of September 30, 2019, the Company’s finance lease payments included no material options to extend lease terms that are reasonably certain of being exercised. In addition, the Company has no legally binding minimum lease payments for leases that have been signed but not yet commenced as of September 30, 2019.

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Weighted-Average Lease Term and Discount Rate

The weighted-average remaining lease term and weighted-average discount rate for the Company’s operating and finance leases were as follows:



	September 30, 2019
Lease Term and Discount Rate:
Weighted-average remaining lease term (years):
Operating leases	2.6
Finance leases	7.3
Weighted-average discount rate:
Operating leases	7.3	%
Finance leases	8.8	%

15. Subsequent Events

On October 11, 2019, the Company issued and sold $550.0 million aggregate principal amount of 2025 Notes, which mature on April 15, 2025 at par. The Company received net proceeds of $540.0 million net of initial purchasers’ discounts and estimated expenses. The Company used the net proceeds along with revolver borrowings and cash on hand to fund the redemption of the 2021 Notes. Interest on the 2025 Notes is paid semiannually in arrears on April 15 and October 15 of each year, beginning on April 15, 2020.

Also on October 11, 2019, with all conditions precedent met, the $99.6 million borrowing base expansion provided for in the First Amendment to the Third Amended and Restated Credit Agreement went into effect. Please read Note 9 - “Long-Term Debt” for further information.

On October 21, 2019, the Company redeemed at par $761.2 million aggregate principal amount outstanding of the remaining 2021 Notes issued in March 2014 with the net proceeds from the issuance of the 2025 Notes, together with borrowings under the Company’s revolving credit facility and cash on hand, at a redemption price of $761.2 million, plus accrued and unpaid interest. Please read Note 9 - “Long-Term Debt” for further information.

On November 10, 2019, the Company entered into a membership interest purchase agreement (the “Purchase Agreement”) with Starlight Relativity Acquisition Company LLC, a Delaware limited liability company (“Starlight”), pursuant to which Starlight acquired from the Company (the “Transaction”) all of the issued and outstanding membership interests in Calumet San Antonio Refining, LLC, a Delaware limited liability company (“Calumet San Antonio”) and wholly owned subsidiary of the Company, with an effective date of November 1, 2019. Calumet San Antonio owns a refinery located in San Antonio, Texas and related assets including associated hydrocarbon inventories and a crude oil terminal and pipeline. The operating results of Calumet San Antonio are reported in our Fuel products segment. The Transaction closed on November 10, 2019.

Under the Purchase Agreement, Starlight paid $63.0 million in cash minus adjustments for net working capital and inventories measured on November 1, 2019 and reimbursement of certain costs. In connection with the Transaction, the Partnership, Calumet San Antonio, TexStar Midstream Logistics, L.P. , TexStar Midstream Logistics Pipeline, LP and Tailwater Capital, LLC entered into a Settlement and Release Agreement (the “Settlement Agreement”), pursuant to which the Partnership agreed to pay TexStar and its affiliates a cash payment of $1.0 million and the parties mutually agreed to dismiss the litigation among the parties with respect to the Throughput and Deficiency Agreement (the “Pipeline Agreement”) and mutually release each other with respect to the legal dispute relating to the termination of the Pipeline Agreement. As a result of the Settlement Agreement, the Company will derecognize the $38.1 million liability related to the Pipeline Agreement.

In 2018, the Company entered into a long-term commitment in the form of a throughput and deficiency agreement for future transportation of West Texas crude oil via third party pipeline facilities presently under construction. This agreement is not included in the sale of Calumet San Antonio and has a maximum present value liability of $20.6 million over its seven year term. The Company is pursuing alternatives in an effort to offset a significant amount of the costs expected under this agreement. However, there can be no assurance that the Company will be successful in realizing the alternatives to reduce these costs. Consequently, in connection with the sale of Calumet San Antonio, the Company will record a liability, of $20.6 million for the present value of the annual costs over its seven year term.

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Major categories of assets and liabilities at their carrying values to be disposed of as of September 30, 2019 consist of the following (in millions).



	September 30, 2019
($ in millions)	(Unaudited)
ASSETS
Current assets:
Accounts receivable, net	$	17.8
Inventories	9.7
Prepaid expenses and other current assets	5.4
Total current assets	32.9
Property, plant and equipment, net	80.8
Operating lease right-of-use assets	1.6
Other noncurrent assets, net	4.3
Total assets	$	119.6
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	46.7
Accrued salaries, wages and benefits	0.2
Other taxes payable	4.4
Other current liabilities	38.2
Current portion of operating lease liabilities	0.7
Total current liabilities	90.2
Long-term operating lease liabilities	1.3
Total liabilities	$	91.5
Commitments and contingencies
Total partners’ capital	28.1
Total liabilities and partners’ capital	$	119.6

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The historical unaudited condensed consolidated financial statements included in this Quarterly Report reflect all of the assets, liabilities and results of operations of Calumet Specialty Products Partners, L.P. (“Calumet,” the “Company,” “we,” “our,” or “us”). The following discussion analyzes the financial condition and results of operations of the Company for the three and nine months ended September 30, 2019 and 2018. In addition, as discussed in Note 5 to the Unaudited Condensed Consolidated Financial Statements, we closed the Anchor Transaction on November 21, 2017. As a result of the Anchor Transaction, we classified the results of operations and the assets and liabilities of Anchor Drilling Fluids USA, LLC (“Anchor”) for all periods presented to reflect Anchor as a discontinued operation. Prior to being reported as discontinued operations, Anchor was included as its own reportable segment as oilfield services. Unitholders should read the following discussion and analysis of our financial condition and results of operations in conjunction with our 2018 Annual Report and our historical unaudited condensed consolidated financial statements and notes included elsewhere in this Quarterly Report.

Overview

We are a leading independent producer of high-quality, specialty hydrocarbon products in North America. We are headquartered in Indianapolis, Indiana, and own specialty and fuel products facilities primarily located in northwest Louisiana, northern Montana, western Pennsylvania, Texas, New Jersey and eastern Missouri. We own and lease additional facilities, primarily related to production and distribution of specialty and fuel products, throughout the United States (“U.S.”). Our business is organized into three segments: our core specialty products segment, fuel products segment and corporate segment. In our specialty products segment, we process crude oil and other feedstocks into a wide variety of customized lubricating oils, solvents, waxes, synthetic lubricants, and other products. Our specialty products are sold to domestic and international customers who purchase them primarily as raw material components for basic industrial, consumer and automotive goods. We also blend and market specialty products through our Royal Purple, Bel-Ray, and TruFuel brands. In our fuel products segment, we process crude oil into a variety of fuel and fuel-related products, including gasoline, diesel, jet fuel, asphalt and other products, and from time to time resell purchased crude oil to third-party customers. Our corporate segment, which was added during the third quarter of 2019, primarily consists of general and administrative expenses not allocated to the specialty products or fuel products segment, Please see Note 13 - “Segments and Related Information” for further information.

Third Quarter 2019 Update

Outlook and Trends

Commodity markets and corresponding fluctuations in product margins have been mixed during the nine months ended September 30, 2019, with the average price per barrel of New York Mercantile Exchange West Texas Intermediate (“NYMEX WTI”) crude oil decreasing by approximately 5.8% in the third quarter of 2019 as compared to the second quarter of 2019. We expect volatility to continue throughout 2019. Below are factors that have impacted or may impact our results of operations during 2019:

•

We continue to focus on improving operations. Our total feedstock runs were 106,784 barrels per day (“bpd”) during the third quarter 2019, compared to 94,866 bpd during the third quarter 2018. This increase is primarily attributed to improved plant utilization rates in the current period in comparison to the prior period when turnaround activities at the Shreveport refinery and certain third-party processing facilities and maintenance activities negatively impacted our operating results. We anticipate secular improvement in our utilization rates as we seek to minimize unplanned downtime at our facilities.


•	Gasoline margins are expected to decline as domestic demand follows typical seasonal patterns. Diesel demand typically declines in the fourth quarter but there is the potential to be positively affected by the implementation of the International Maritime Organization 2020 regulations.


•	Asphalt demand is expected to decline in the fourth quarter of 2019 due to the seasonality of the road construction and roofing industries.

•

Environmental regulations continue to affect our margins in the form of the cost of RINs. To the extent we are unable to blend biofuels, we must purchase RINs in the open market to satisfy our annual requirement. The approximate 35% decrease in the price of RINs during the third quarter 2019 favorably affected our results of operations, as did the receipt of the RINs exemptions for all three of our fuels refineries. It is not possible to predict what future RINs volumes or costs may be given the volatile price of RINs, but we continue to anticipate that RINs have the potential to remain a significant expense for our fuel products segment (inclusive of the favorable impact of exemptions received), assuming current market prices for RINs continue.

•

Canadian heavy sour crude oil discounts have narrowed in comparison to the wide discounts seen throughout much of 2018 caused by the oversupply of sour crude oil and pipeline constraints restricting access to markets. The price of domestically produced mid-continent crude is expected to continue to trade at a discount relative to internationally produced crude reflecting increased domestic production combined with transportation constraints. Processing crude oils priced based on WCS and other cost-advantaged crudes will continue to be a focus of ours in 2019.


•	Specialty product margins, as a percentage of sales, have remained relatively stable and are expected to remain stable in the near term. We continue to consider our specialty products segment our core business over the long term, and we plan to seek appropriate ways to further invest in our specialty products segment.

•

We continue to evaluate opportunities to divest non-core businesses and assets in line with our strategy of preserving liquidity and streamlining our business to better focus on the advancement of our core business. In addition, we may also consider the disposition of certain core assets or businesses, to the extent such a transaction would improve our capital structure or otherwise be accretive to the Company. There can be no assurance as to the timing or success of any such potential transaction, or any other transaction, or that we will be able to sell such assets or businesses on satisfactory terms, if at all. In addition, our acquisition program targets assets that management believes will be financially accretive, and we intend to focus on targeted strategic acquisitions of specialty products assets that leverage an existing core competency and that have an identifiable competitive advantage we can exploit as the new owner.

Key Matters, Claims and Legal Proceedings

We were a party to a 2014 Throughput and Deficiency Agreement with TexStar Midstream Logistics, L.P. (“TexStar”) pursuant to which TexStar delivered crude oil to our San Antonio refinery through a crude oil pipeline system owned and operated by TexStar (the “Pipeline Agreement”). The Pipeline Agreement had an initial term of 20 years and was accounted for as a finance lease on our condensed consolidated balance sheets. TexStar and us has each terminated the Pipeline Agreement for alleged breaches of the agreement. We ceased using the asset as of February 28, 2019, wrote off the associated net book value of $10.7 million to loss on impairment and disposal of assets in our unaudited condensed consolidated statement of operations and reclassified the $38.1 million present value of financing lease obligation from current and long-term debt to other current liabilities on the condensed consolidated balance sheets. We are in dispute with TexStar over whether any additional monies are owed with TexStar claiming certain minimum amounts of $0.0 to $0.5 million a month continue to be owed through the remainder of the original term of the Pipeline Agreement. The Company filed a lawsuit against TexStar on May 17, 2019 in Bexar County, Texas, seeking a declaratory judgment that the Company properly terminated the Pipeline Agreement and the Company is not obligated to make further payments under the Pipeline Agreement. The litigation is currently pending. The Company believes it will prevail in the dispute over whether

further payments are owed, but pending resolution, the $38.1 million is recorded as a current liability on its condensed consolidated balance sheets. On November 10, 2019, the Company, TexStar, and related parties entered into a Settlement and Release Agreement with respect to the litigation. Please see Note 15 - “Subsequent Events” for further information.

Financial Results

We reported a net loss from continuing operations of $4.6 million in the third quarter 2019, versus a net loss from continuing operations of $16.0 million in the third quarter 2018. We reported Adjusted EBITDA from continuing operations (as defined in “Non-GAAP Financial Measures”) of $73.5 million in the third quarter 2019, versus $54.5 million in the third quarter 2018. We generated cash from continuing operating activities of $153.9 million through the third quarter 2019, driven by improved business performance that resulted in an increase in gross profit, lower interest expense and reductions in net working capital. The Company used cash in continuing operating activities operations of $29.3 million through the third quarter 2018.

Please read “— Non-GAAP Financial Measures” for a reconciliation of EBITDA, Adjusted EBITDA and Distributable Cash Flow to net income (loss), our most directly comparable financial performance measure calculated and presented in accordance with U.S. generally accepted accounting principles (“GAAP”).

Commodity markets remained volatile in the third quarter 2019, contributing to fluctuations in refined product margins. The average price of NYMEX WTI crude oil decreased by approximately 18.7% in the third quarter 2019, when compared to the same period in 2018. In the third quarter 2019, the average price differential per barrel between Western Canadian Select (“WCS”) crude oil and NYMEX WTI averaged $13 per barrel below NYMEX WTI, versus $29 per barrel below NYMEX WTI in the third quarter 2018. Given our access to cost advantaged, heavy Canadian crude oil in our northern refining system, we have embarked on a multi-year plan to increase our ability to process this crude oil grade over time based on market conditions and pricing. In the third quarter 2019, we processed approximately 25,600 bpd of heavy Canadian crude oil, versus 24,400 bpd in the third quarter 2018.

Specialty products segment Adjusted EBITDA was $52.5 million in the third quarter 2019, versus $36.6 million in the third quarter 2018. Specialty products third quarter 2019 segment Adjusted EBITDA was primarily impacted by increased production and stronger margins. Pricing weakness across the paraffinic base oil market continues to be a challenge, but has been offset by strengthening in our other specialty product lines. Third quarter 2019 results were impacted by a $0.9 million favorable LCM inventory adjustment compared to a $0.5 million unfavorable LCM inventory adjustment in the third quarter 2018.

Fuel products segment Adjusted EBITDA was $44.1 million during the third quarter 2019, versus $41.9 million in the third quarter 2018, due primarily to increased sales volume as a result of improved plant utilization rates, and slightly higher U.S. Gulf Coast 2/1/1 crack spreads (“Gulf Coast crack spread”), offset by the tightening of WCS and WTI Midland differentials to NYMEX WTI when comparing periods. Third quarter 2019 results were impacted by a $3.6 million unfavorable LCM inventory adjustment compared to a $1.8 million unfavorable LCM inventory adjustment in the third quarter 2018.

Corporate segment Adjusted EBITDA was $23.1 million in the third quarter 2019 versus $24.0 million in the third quarter 2018, due primarily from interest income as a result of the cash reserves used to effect the debt reduction during 2019.

For benchmarking purposes, we compare our per barrel refined fuel products margin to the Gulf Coast crack spread. The Gulf Coast crack spread represents the approximate gross margin per barrel that results from processing two barrels of crude oil into one barrel of gasoline and one barrel of ultra-low sulfur diesel fuel. The Gulf Coast crack spread is calculated using the near-month futures price of NYMEX WTI crude oil, the price of U.S. Gulf Coast Pipeline 87 Octane Conventional Gasoline and the price of U.S. Gulf Coast Pipeline Ultra-Low Sulfur Diesel (“ULSD”). During the third quarter 2019, the Gulf Coast crack spread averaged approximately $19 per barrel compared to approximately $18 per barrel in the same period in 2018, an approximate 2.2% increase. The Gulf Coast ULSD crack spread averaged approximately $21 per barrel during the third quarter 2019 and $20 per barrel in the third quarter 2018. The Gulf Coast gasoline crack spread averaged approximately $16 per barrel during the third quarter 2019, compared to approximately $16 per barrel in the same period in 2018.

Liquidity Update

As of September 30, 2019, we had total liquidity of $437.7 million comprised of $164.2 million of cash and availability under our revolving credit facility of $273.5 million. As of September 30, 2019, we had a $343.6 million borrowing base, $70.1 million in outstanding standby letters of credit and no outstanding borrowings. We believe we will continue to have sufficient liquidity from cash on hand, projected cash flow from operations, borrowing capacity and other means by which to meet our financial commitments, debt service obligations, contingencies and anticipated capital expenditures.

On September 4, 2019, we entered into the first amendment to the third amended and restated senior secured revolving credit facility. The amendment expands the borrowing base by $99.6 million on the Effective Date (as defined in the amendment) by adding the fixed assets of our Great Falls, MT refinery as collateral for the bank group. The $99.6 million expansion amortizes to zero on a straight-line basis over ten quarters starting in the first quarter of 2020. Additionally, while the fixed assets of the Great Falls, MT refinery are included in the borrowing base, the amendment provides for a 25 basis points increase in the applicable margin rates, as well as increases in the minimum availability under the revolving credit facility required for us to be able to perform certain actions, including to make restricted payments of other distributions, sell or dispose of certain assets, make acquisitions or investments, or prepay other indebtedness. The proceeds of this borrowing base expansion along with cash on hand and proceeds from the new 2025 Notes offering will be used to retire the 2021 Notes. Please read Note 15 - “Subsequent Events” for additional information.

Renewable Fuel Standard Update

Along with the broader refining industry, we remain subject to compliance costs under the Renewable Fuel Standard (“RFS”). Under the regulation of the EPA, the RFS provides annual requirements for the total volume of renewable fuels which are mandated to be blended into finished transportation fuels. If a refiner does not meet its required annual Renewable Volume Obligation, the refiner can purchase blending credits in the open market, referred to as RINs. On October 28, 2019, the EPA published a supplemental notice of proposed rulemaking that will effectively increase the RINs Obligations of non-exempt refiners and other obligates parties beginning in compliance year 2020. The EPA held a public hearing on the supplemental proposal on October 30, 2019 and plans to issue a final rule in 2019.

During the third quarter 2019, we recognized a RINs gain of $11.0 million, compared to a RINs expense of $1.8 million, for the third quarter 2018. For the full-year 2019, we anticipate our gross RINs Obligation will be 85 million RINs. Estimated RINs Obligations remain subject to fluctuations in fuels production volumes during the full-year 2019. The gross RINs Obligations exclude the potential for any subsequent hardship waivers.

In August 2019, the EPA granted the Company’s fuel products refineries a “small refinery exemption” under the RFS for the compliance year 2018, as provided for under the CAA. In granting those exemptions, the EPA, in consultation with the Department of Energy, determined that for the compliance year 2018, compliance with the RFS would represent a “disproportionate economic hardship” for these small refineries. The RINs exemption resulted in a decrease in the RINs Obligation and is charged to cost of sales in the unaudited condensed consolidated statement of operations for the three and nine months ended September 30, 2019.

We continue to anticipate that expenses related to RFS compliance have the potential to remain a significant expense for our fuel products segment, assuming current market prices for RINs continue.

Key Performance Measures

Our sales and net loss are principally affected by the price of crude oil, demand for specialty products and fuel products, prevailing crack spreads for fuel products, the price of natural gas used as fuel in our operations and our results from derivative instrument activities.

Our primary raw materials are crude oil and other specialty feedstocks, and our primary outputs are specialty petroleum products and fuel products. The prices of crude oil, specialty products and fuel products are subject to fluctuations in response to changes in supply, demand, market uncertainties and a variety of factors beyond our control. We monitor these risks and from

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time-to-time enter into derivative instruments designed to help mitigate the impact of commodity price fluctuations on our business. The primary purpose of our commodity risk management activities is to economically hedge our cash flow exposure to commodity price risk so that we can meet our debt service and capital expenditure requirements despite fluctuations in crude oil and fuel products prices. We also may hedge when market conditions exist that we believe to be out of the ordinary and particularly supportive of our financial goals. We enter into derivative contracts for future periods in quantities that do not exceed our projected purchases of crude oil and natural gas and sales of fuel products. Please read Part I, Item 3 “Quantitative and Qualitative Disclosures About Market Risk — Commodity Price Risk” and Note 10 — “Derivatives” under Part I, Item 1 “Financial Statements — Notes to Unaudited Condensed Consolidated Financial Statements.”

Our management uses several financial and operational measurements to analyze our performance. These measurements include the following:


•	sales volumes;


•	production yields;


•	segment gross profit;


•	segment Adjusted EBITDA; and


•	selling, general and administrative expenses.

Sales volumes. We view the volumes of specialty products and fuel products sold as an important measure of our ability to effectively utilize our operating assets. Our ability to meet the demands of our customers is driven by the volumes of crude oil and feedstocks that we run at our facilities. Higher volumes improve profitability both through the spreading of fixed costs over greater volumes and the additional gross profit achieved on the incremental volumes.

Production yields. In order to maximize our gross profit and minimize lower margin products, we seek the optimal product mix for each barrel of crude oil we refine, or feedstocks we, or third parties, process, which we refer to as production yield.

Segment gross profit. Specialty products and fuel products gross profit are important measures of our ability to maximize the profitability of our specialty products and fuel products segments. We define gross profit as sales less the cost of crude oil and other feedstocks and other production-related expenses, the most significant portion of which includes labor, plant fuel, utilities, contract services, maintenance, depreciation and processing materials. We use gross profit as an indicator of our ability to manage our business during periods of crude oil and natural gas price fluctuations, as the prices of our specialty products and fuel products generally do not change immediately with changes in the price of crude oil and natural gas. The increase or decrease in selling prices typically lags behind the rising or falling costs, respectively, of crude oil feedstocks for specialty products. Other than plant fuel, production-related expenses generally remain stable across broad ranges of specialty products and fuel products throughput volumes but can fluctuate depending on maintenance activities performed during a specific period.

Our fuel products segment gross profit per barrel may differ from standard U.S. Gulf Coast, PADD 4 Billings, Montana or 3/2/1 and 2/1/1 market crack spreads due to many factors, including our fuel products mix as shown in our production table being different than the ratios used to calculate such market crack spreads, LCM inventory adjustments reflected in gross profit, operating costs including fixed costs, actual crude oil costs differing from market indices and our local market pricing differentials for fuel products in the Shreveport, Louisiana, San Antonio, Texas, and Great Falls, Montana vicinities as compared to U.S. Gulf Coast and PADD 4 Billings, Montana postings.

Segment Adjusted EBITDA. We believe that specialty products and fuel products segment Adjusted EBITDA measures are useful as they exclude transactions not related to our core cash operating activities and provide metrics to analyze our ability to pay distributions to our unitholders and pay interest to our noteholders as Adjusted EBITDA is a component in the calculation of Distributable Cash Flow and allows us to meaningfully analyze the trends and performance of our core cash operations as well as to make decisions regarding the allocation of resources to segments. The corporate segment Adjusted EBITDA primarily reflects general and administrative costs not related to our core cash operating activities.

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Results of Operations for the Three and Nine Months Ended September 30, 2019 and 2018

Production Volume. The following table sets forth information about our combined operations from continuing operations. Facility production volume differs from sales volume due to changes in inventories and the sale of purchased fuel product blendstocks such as ethanol and biodiesel and the resale of crude oil in our fuel products segment.



	Three Months Ended September 30,				Nine Months Ended September 30,
	2019	2018	% Change		2019	2018	% Change
	(In bpd)				(In bpd)
Total sales volume ⁽¹⁾	111,022	100,793	10.1	%	107,670	97,150	10.8	%
Total feedstock runs ⁽²⁾	110,447	101,220	9.1	%	106,784	94,866	12.6	%
Facility production: ⁽³⁾
Specialty products:
Lubricating oils	11,937	11,716	1.9	%	11,872	11,840	0.3	%
Solvents	7,493	7,728	(3.0	)%	7,580	7,812	(3.0	)%
Waxes	1,440	1,106	30.2	%	1,416	1,172	20.8	%
Packaged and synthetic specialty products ⁽⁴⁾	1,384	2,052	(32.6	)%	1,667	2,314	(28.0	)%
Other	2,037	3,106	(34.4	)%	1,626	2,305	(29.5	)%
Total	24,291	25,708	(5.5	)%	24,161	25,443	(5.0	)%
Fuel products:
Gasoline	23,603	21,514	9.7	%	23,816	20,179	18.0	%
Diesel	30,479	30,818	(1.1	)%	29,729	27,315	8.8	%
Jet fuel	5,213	3,060	70.4	%	4,462	3,168	40.8	%
Asphalt, heavy fuels and other	22,248	21,174	5.1	%	21,031	19,673	6.9	%
Total	81,543	76,566	6.5	%	79,038	70,335	12.4	%
Total facility production ⁽³⁾	105,834	102,274	3.5	%	103,199	95,778	7.7	%

⁽¹⁾

Total sales volume includes sales from the production at our facilities and certain third-party facilities pursuant to supply and/or processing agreements, sales of inventories and the resale of crude oil to third-party customers. Total sales volume includes the sale of purchased fuel product blendstocks, such as ethanol and biodiesel, as components of finished fuel products in our fuel products segment sales.

The increase in total sales volume for the three and nine months ended September 30, 2019, as compared to the same periods in 2018, is due primarily to improved plant utilization during 2019. During 2018, turnaround activities at the Shreveport refinery and certain third-party processing facilities and maintenance activities negatively impacted our sales volumes.


⁽²⁾	Total feedstock runs represent the barrels per day of crude oil and other feedstocks processed at our facilities and at certain third-party facilities pursuant to supply and/or processing agreements.

The increase in total feedstock runs for the three and nine months ended September 30, 2019, as compared to the same periods in 2018, is due primarily to improved plant utilization. During 2018, turnaround activities at the Shreveport refinery and certain third-party processing facilities and maintenance activities negatively impacted our feedstock runs.

⁽³⁾

Total facility production represents the barrels per day of specialty products and fuel products yielded from processing crude oil and other feedstocks at our facilities and at certain third-party facilities pursuant to supply and/or processing agreements. The difference between total facility production and total feedstock runs is primarily a result of the time lag between the input of feedstocks and production of finished products and volume loss.

The change in total facility production for the three and nine months ended September 30, 2019, as compared to the same periods in 2018, is due primarily to the operational items discussed above.


⁽⁴⁾	Represents production of finished lubricants and chemicals specialty products including the products from the Royal Purple, Bel-Ray and Calumet Packaging facilities.

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The following table reflects our unaudited condensed consolidated results of operations and includes the non-GAAP financial measures EBITDA, Adjusted EBITDA and Distributable Cash Flow. For a reconciliation of EBITDA, Adjusted EBITDA and Distributable Cash Flow to Net loss and Net cash provided by (used in) operating activities, our most directly comparable financial performance and liquidity measures calculated and presented in accordance with GAAP, please read “— Non-GAAP Financial Measures.”



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
	(In millions)
Sales	$	929.6		$	953.5		$	2,677.8		$	2,649.5
Cost of sales	811.8			850.2			2,316.9			2,313.7
Gross profit	117.8			103.3			360.9			335.8
Operating costs and expenses:
Selling	12.6			12.2			40.2			39.6
General and administrative	32.8			29.2			105.5			95.5
Transportation	28.4			36.4			95.9			99.7
Taxes other than income taxes	5.7			5.9			15.5			13.2
Loss on impairment and disposal of assets	3.2			—			31.1			—
Other operating (income) expense	1.7			(2.0		)	0.8			(18.7		)
Operating income	33.4			21.6			71.9			106.5
Other income (expense):
Interest expense	(33.8		)	(37.7		)	(99.2		)	(120.4		)
Gain (loss) from debt extinguishment	—			—			0.7			(58.8		)
Gain (loss) on derivative instruments	(5.0		)	(2.7		)	14.4			(2.0		)
Other	1.3			3.2			7.9			5.6
Total other expense	(37.5		)	(37.2		)	(76.2		)	(175.6		)
Net loss from continuing operations before income taxes	(4.1		)	(15.6		)	(4.3		)	(69.1		)
Income tax expense from continuing operations	0.5			0.4			0.7			1.0
Net loss from continuing operations	$	(4.6	)	$	(16.0	)	$	(5.0	)	$	(70.1	)
Net loss from discontinued operations, net of tax	$	—		$	(0.5	)	$	—		$	(3.1	)
Net loss	$	(4.6	)	$	(16.5	)	$	(5.0	)	$	(73.2	)
EBITDA	$	57.1		$	51.2		$	177.5		$	137.0
Adjusted EBITDA	$	73.5		$	54.3		$	250.8		$	208.2
Distributable Cash Flow	$	16.8		$	10.0		$	108.2		$	69.5

Non-GAAP Financial Measures

We include in this Quarterly Report the non-GAAP financial measures EBITDA, Adjusted EBITDA and Distributable Cash Flow. We provide reconciliations of EBITDA, Adjusted EBITDA and Distributable Cash Flow to Net loss, our most directly comparable financial performance measure. We also provide a reconciliation of Distributable Cash Flow, Adjusted EBITDA and EBITDA to Net cash provided by (used in) operating activities, our most directly comparable liquidity measure. Both Net income (loss) and Net cash provided by (used in) operating activities are calculated and presented in accordance with GAAP.

EBITDA, Adjusted EBITDA and Distributable Cash Flow are used as supplemental financial measures by our management and by external users of our financial statements such as investors, commercial banks, research analysts and others, to assess:


•	the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;


•	the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness;


•	our operating performance and return on capital as compared to those of other companies in our industry, without regard to financing or capital structure; and


•	the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

Management believes that these non-GAAP measures are useful to analysts and investors as they exclude transactions not related to our core cash operating activities and provide metrics to analyze our ability to pay interest costs and distributions. However, the indentures governing our senior notes contain covenants that, among other things, restrict our ability to pay distributions. We believe that excluding these transactions allows investors to meaningfully analyze trends and performance of our core cash operations.

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We define EBITDA for any period as net income (loss) plus interest expense (including debt issuance costs), income taxes and depreciation and amortization.

We define Adjusted EBITDA for any period as EBITDA adjusted for (a) impairment; (b) unrealized gains and losses from mark to market accounting for hedging activities; (c) realized gains and losses under derivative instruments excluded from the determination of net income (loss); (d) 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); (e) debt refinancing fees, premiums and penalties; (f) any net loss realized in connection with an asset sale that was deducted in computing net income (loss) and (g) all extraordinary, unusual or non-recurring items of gain or loss, or revenue or expense.

We define Distributable Cash Flow for any period as Adjusted EBITDA less replacement and environmental capital expenditures, turnaround costs, cash interest expense (consolidated interest expense less non-cash interest expense), income (loss) from unconsolidated affiliates, net of cash distributions and income tax expense (benefit).

The definition of Adjusted EBITDA presented in this Quarterly Report is consistent with the calculation of “Consolidated Cash Flow” contained in the indentures governing our 2021 Notes, 2022 Notes and 2023 Notes (as defined in this Quarterly Report). We are required to report Consolidated Cash Flow to the holders of our 2021 Notes, 2022 Notes and 2023 Notes and Adjusted EBITDA to the lenders under our revolving credit facility, and these measures are used by them to determine our compliance with certain covenants governing those debt instruments. Please read Part I, Item 2 “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Debt and Credit Facilities” for additional details regarding the covenants governing our debt instruments.

EBITDA, Adjusted EBITDA and Distributable Cash Flow should not be considered alternatives to Net income (loss), Operating income, Net cash provided by (used in) operating activities or any other measure of financial performance presented in accordance with GAAP. In evaluating our performance as measured by EBITDA, Adjusted EBITDA and Distributable Cash Flow, management recognizes and considers the limitations of these measurements. EBITDA and Adjusted EBITDA do not reflect our obligations for the payment of income taxes, interest expense or other obligations such as capital expenditures. Accordingly, EBITDA, Adjusted EBITDA and Distributable Cash Flow are only three of several measurements that management utilizes. Moreover, our EBITDA, Adjusted EBITDA and Distributable Cash Flow may not be comparable to similarly titled measures of another company because all companies may not calculate EBITDA, Adjusted EBITDA and Distributable Cash Flow in the same manner.

The following tables present a reconciliation of Net loss to EBITDA, Adjusted EBITDA and Distributable Cash Flow; Distributable Cash Flow, Adjusted EBITDA and EBITDA to Net cash provided by (used in) operating activities; and Segment Adjusted EBITDA to EBITDA and Net loss our most directly comparable GAAP financial performance and liquidity measures, for each of the periods indicated.

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	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
	(In millions)
Reconciliation of Net loss to EBITDA, Adjusted EBITDA and Distributable Cash Flow:
Net loss	$	(4.6	)	$	(16.5	)	$	(5.0	)	$	(73.2	)
Add:
Interest expense	33.8			37.7			99.2			120.4
Depreciation and amortization	27.4			29.6			82.6			88.8
Income tax expense	0.5			0.4			0.7			1.0
EBITDA	$	57.1		$	51.2		$	177.5		$	137.0
Add:
Unrealized (gain) loss on derivative instruments	$	5.4		$	2.4		$	20.2		$	(0.4	)
Realized loss on derivatives, not included in net loss or settled in a prior period	—			0.7			—			2.8
Amortization of turnaround costs	6.1			2.7			16.5			8.7
(Gain) loss from debt extinguishment	—			—			(0.7		)	58.8
Loss on impairment and disposal of assets	3.2			—			31.1			—
Gain on sale of unconsolidated affiliate ⁽³⁾	—			—			(1.2		)	—
Equity based compensation and other items	0.4			(2.7		)	6.1			1.3
Other non-recurring expenses	1.3			—			1.3			—
Adjusted EBITDA ⁽⁴⁾	$	73.5		$	54.3		$	250.8		$	208.2
Less:
Replacement and environmental capital expenditures ⁽¹⁾	$	13.4		$	4.4		$	27.0		$	16.0
Cash interest expense ⁽²⁾	32.4			36.0			94.3			114.3
Turnaround costs	10.4			3.5			16.8			11.1
Income (loss) from unconsolidated affiliates ⁽³⁾	—			—			3.8			(3.7		)
Income tax expense	0.5			0.4			0.7			1.0
Distributable Cash Flow	$	16.8		$	10.0		$	108.2		$	69.5

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	Nine Months Ended September 30,
	2019			2018
	(In millions)
Reconciliation of Distributable Cash Flow, Adjusted EBITDA and EBITDA to Net cash provided by (used in) operating activities:
Distributable Cash Flow	$	108.2		$	69.5
Add:
Replacement and environmental capital expenditures ⁽¹⁾	27.0			16.0
Cash interest expense ⁽²⁾	94.3			114.3
Turnaround costs	16.8			11.1
Income (loss) from unconsolidated affiliates ⁽³⁾	3.8			(3.7		)
Income tax expense	0.7			1.0
Adjusted EBITDA ⁽⁴⁾	$	250.8		$	208.2
Less:
Unrealized (gain) loss on derivative instruments	$	20.2		$	(0.4	)
Realized loss on derivatives, not included in net loss or settled in a prior period	—			2.8
Amortization of turnaround costs	16.5			8.7
(Gain) loss from debt extinguishment	(0.7		)	58.8
Loss on impairment and disposal of assets	31.1			—
Gain on sale of unconsolidated affiliate ⁽³⁾	(1.2		)	—
Equity based compensation and other items	6.1			1.3
Other non-recurring expenses	1.3			—
EBITDA	$	177.5		$	137.0
Add:
Unrealized (gain) loss on derivative instruments	$	20.2		$	(0.4	)
Cash interest expense ⁽²⁾	(94.3		)	(114.3		)
Equity based compensation	4.9			2.8
Lower of cost or market inventory adjustment	(38.8		)	(12.0		)
(Income) loss from unconsolidated affiliates ⁽³⁾	(3.8		)	3.7
Gain on sale of unconsolidated affiliate ⁽³⁾	(1.2		)	—
Amortization of turnaround costs	16.5			8.7
(Gain) loss from debt extinguishment	(0.7		)	58.8
Operating lease expense	57.1			—
Operating lease payments	(57.1		)	—
Loss on impairment and disposal of assets	31.1			—
Income tax expense	(0.7		)	(1.0		)
Changes in assets and liabilities:
Accounts receivable	(49.8		)	29.0
Inventories	29.6			(34.4		)
Other current assets	4.6			(3.8		)
Derivative activity	(0.4		)	(0.4		)
Turnaround costs	(16.8		)	(11.1		)
Accounts payable	61.7			(32.5		)
Accrued interest payable	10.8			(7.0		)
Other current liabilities	5.5			(48.7		)
Other	(2.0		)	(3.7		)
Net cash provided by (used in) operating activities	$	153.9		$	(29.3	)

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	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
	(In millions)
Reconciliation of Adjusted EBITDA to EBITDA and Net loss:
Segment Adjusted EBITDA
Specialty products Adjusted EBITDA	$	52.5		$	36.6		$	171.3		$	129.3
Fuel products Adjusted EBITDA	44.1			41.9			155.5			155.3
Corporate Adjusted EBITDA	(23.1		)	(24.0		)	(76.0		)	(74.4		)
Discontinued operations Adjusted EBITDA	—			(0.2		)	—			(2.0		)
Total Adjusted EBITDA ⁽⁴⁾	$	73.5		$	54.3		$	250.8		$	208.2
Less:
Unrealized (gain) loss on derivative instruments	$	5.4		$	2.4		$	20.2		$	(0.4	)
Realized loss on derivatives, not included in net loss or settled in a prior period	—			0.7			—			2.8
Amortization of turnaround costs	6.1			2.7			16.5			8.7
Gain (loss) from debt extinguishment	—			—			(0.7		)	58.8
Gain on sale of unconsolidated affiliate ⁽³⁾	—			—			(1.2		)	—
Loss on impairment and disposal of assets	3.2			—			31.1			—
Equity based compensation and other items	0.4			(2.7		)	6.1			1.3
Other non-recurring expenses	1.3			—			1.3			—
EBITDA	$	57.1		$	51.2		$	177.5		$	137.0
Less:
Interest expense	$	33.8		$	37.7		$	99.2		$	120.4
Depreciation and amortization	27.4			29.6			82.6			88.8
Income tax expense	0.5			0.4			0.7			1.0
Net loss	$	(4.6	)	$	(16.5	)	$	(5.0	)	$	(73.2	)


⁽¹⁾	Replacement capital expenditures are defined as those capital expenditures which do not increase operating capacity or reduce operating costs and exclude turnaround costs. Environmental capital expenditures include asset additions to meet or exceed environmental and operating regulations.


⁽²⁾	Represents consolidated interest expense less non-cash interest expense.

⁽³⁾

In 2018, the Company and The Heritage Group formed Biosyn Holdings, LLC (“Biosyn”) for the purposes of acquiring Biosynthetic Technologies, LLC (“Biosynthetic Technologies”), a startup company which developed an intellectual property portfolio for the manufacture of renewable-based and biodegradable esters. The initial cash investment of $3.8 million made by the Company into Biosyn was expensed in the period ended March 31, 2018 given Biosyn’s operations were all related to research and development. The Company accounts for its ownership in Biosyn under the equity method of accounting. During March 2019, the Company sold its investment to The Heritage Group and recognized a gain of $5.0 million. For comparability purposes, $3.8 million of the gain is included in Adjusted EBITDA for the nine months ended September 30, 2019.


⁽⁴⁾	Total Adjusted EBITDA includes the non-cash impact of the following LCM inventory adjustments and losses related to the liquidation of LIFO inventory layers.



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
	(In millions)
LCM Impact	$	(2.7	)	$	(3.0	)	$	38.8		$	12.0
LIFO Impact	$	—		$	—		$	(0.9	)	$	—

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Changes in Results of Operations for the Three Months Ended September 30, 2019 and 2018

Sales. Sales from continuing operations decreased $23.9 million, or 2.5%, to $929.6 million in the three months ended September 30, 2019, from $953.5 million in the same period in 2018. Sales for each of our principal product categories in these periods were as follows:



	Three Months Ended September 30,
	2019		2018		% Change
	(Dollars in millions, except barrel and per barrel data)
Sales by segment:
Specialty products:
Lubricating oils	$	156.1	$	146.6	6.5	%
Solvents	86.1		88.3		(2.5	)%
Waxes	30.1		30.1		—	%
Packaged and synthetic specialty products ⁽¹⁾	59.6		64.0		(6.9	)%
Other ⁽²⁾	23.9		20.2		18.3	%
Total specialty products	$	355.8	$	349.2	1.9	%
Total specialty products sales volume (in barrels)	2,359,000		2,116,000		11.5	%
Average specialty products sales price per barrel	$	150.83	$	165.03	(8.6	)%

Fuel products:
Gasoline	$	189.5	$	191.2	(0.9	)%
Diesel	225.4		257.5		(12.5	)%
Jet fuel	39.5		28.1		40.6	%
Asphalt, heavy fuel oils and other ⁽³⁾	119.4		127.5		(6.4	)%
Total fuel products	$	573.8	$	604.3	(5.0	)%
Total fuel products sales volume (in barrels)	7,855,000		7,157,000		9.8	%
Average fuel products sales price per barrel	$	73.05	$	84.43	(13.5	)%

Total sales	$	929.6	$	953.5	(2.5	)%
Total specialty and fuel products sales volume (in barrels)	10,214,000		9,273,000		10.1	%


⁽¹⁾	Represents packaged and synthetic specialty products at the Royal Purple, Bel-Ray and Calumet Packaging facilities.


⁽²⁾	Represents (a) by-products, including fuels and asphalt, produced in connection with the production of specialty products at the Princeton and Cotton Valley refineries and Dickinson and Karns City facilities and (b) polyolester synthetic lubricants produced at the Missouri facility.


⁽³⁾	Represents asphalt, heavy fuel oils and other products produced in connection with the production of fuels at the Shreveport, San Antonio and Great Falls refineries and crude oil sales from the San Antonio refinery to third-party customers.

The components of the $6.6 million increase in specialty products segment sales for the three months ended September 30, 2019, as compared to the three months ended September 30, 2018, were as follows:



	Dollar Change
	(In millions)
Volume	40.1
Sales price	(33.5		)
Total specialty products segment sales increase	$	6.6

Specialty products segment sales increased $6.6 million period over period, or 1.9%, primarily due to an increase in sales volume offset by a decrease in the average selling price per barrel. The 11.5% increase in sales volume is primarily the result of increased utilization and efficiency during the period compared to the same period in 2018 where there was significant downtime. The average selling price per barrel decreased $14.20, or 8.6%, resulting in a $33.5 million decrease in sales, driven by a nearly $12.00 decrease in the average cost of crude oil per barrel. The decrease in the average selling price was primarily due to a decrease in NYMEX WTI crude oil prices during the third quarter of 2019.

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The components of the $30.5 million decrease in fuel products segment sales for the three months ended September 30, 2019, as compared to the three months ended September 30, 2018, were as follows:



	Dollar Change
	(In millions)
Volume	59.0
Sales price	(89.5		)
Total fuel products segment sales decrease	$	(30.5	)

Fuel products segment sales decreased $30.5 million period over period, or 5.0%, primarily due to a decrease in the average selling price per barrel, partially offset by increased sales volume. The 9.8% increase in sales volume is the result of improved plant utilization in 2019 as compared to the same period in 2018 where there was significant downtime. The average selling price per barrel decreased $11.39, or 13.5%, resulting in a $89.5 million decrease in sales, primarily driven by a nearly $9.00 decrease in the average cost of crude oil per barrel. The decrease in the average selling price per barrel was primarily due to market conditions.

Gross Profit. Gross profit from continuing operations increased $14.5 million, or 14.0%, to $117.8 million in the three months ended September 30, 2019, from $103.3 million in the same period in 2018. Gross profit for our specialty and fuel products segments were as follows:



	Three Months Ended September 30,
	2019			2018			% Change
	(Dollars in millions, except per barrel data)
Gross profit by segment:
Specialty products:
Gross profit	$	80.7		$	68.4		18.0	%
Percentage of sales	22.7		%	19.6		%
Specialty products gross profit per barrel	$	34.21		$	32.33		5.8	%
Fuel products:
Gross profit	$	37.1		$	34.9		6.3	%
Percentage of sales	6.5		%	5.8		%
Fuel products gross profit per barrel	$	4.72		$	4.88		(3.1	)%
Total gross profit	$	117.8		$	103.3		14.0	%
Percentage of sales	12.7		%	10.8		%

The components of the $12.3 million increase in specialty products segment gross profit for the three months ended September 30, 2019, as compared to the three months ended September 30, 2018, were as follows:



	Dollar Change
	(In millions)
Three months ended September 30, 2018 reported gross profit	$	68.4
Sales price	(33.5		)
Operating costs	(1.3		)
LIFO inventory layer adjustment	0.1
LCM inventory adjustment	1.4
Volume	13.5
Cost of materials	32.1
Three months ended September 30, 2019 reported gross profit	$	80.7

The increase in specialty products segment gross profit of $12.3 million for the three months ended September 30, 2019, as compared to the same period in 2018, was due primarily to a decrease in the cost of materials of $32.1 million, an increase in sales volume and a favorable LCM inventory adjustment of $1.4 million, partially offset by decrease in sales price and an increase in operating costs. Sales price and cost of materials, net, decreased gross profit by $1.4 million, as the average selling price per barrel decreased $14.20 driven by a decrease of nearly $12.00 in the average cost of crude oil per barrel and other market conditions. The increase in sales volume was due primarily to increased utilization and efficiency during the period compared to the same period in 2018. The increase in operating costs was primarily due to increased incentive compensation costs, increased depreciation and amortization and increased repairs and maintenance, partially offset by decreased professional services.

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The components of the $2.2 million increase in fuel products segment gross profit for the three months ended September 30, 2019, as compared to the three months ended September 30, 2018, were as follows:



	Dollar Change
	(In millions)
Three months ended September 30, 2018 reported gross profit	$	34.9
Sales Price	(89.5		)
Operating costs	(2.1		)
LCM inventory adjustment	(1.8		)
LIFO inventory layer adjustment	0.3
Volume	11.0
RINs expense	12.8
Cost of materials	71.5
Three months ended September 30, 2019 reported gross profit	$	37.1

The increase in fuel products segment gross profit of $2.2 million for the three months ended September 30, 2019, as compared to the same period in 2018, was primarily due to a decrease in the cost of materials of $71.5 million, a decrease in RINs expense of $12.8 million and an increase in volume, partially offset by a decrease in sales price, an increase in operating costs and an unfavorable LCM inventory adjustment of $1.8 million. Sales price and cost of materials, net, decreased gross profit by $18.0 million, as the average selling price per barrel decreased by $11.39 driven by a decrease of nearly $9.00 in the average cost of crude oil per barrel and other market conditions. The increase in operating costs was primarily due to increases in incentive compensation costs, partially offset by a decrease in repairs and maintenance expense.

Selling. Selling expenses from continuing operations increased $0.4 million, or 3.3%, to $12.6 million in the three months ended September 30, 2019, from $12.2 million in the same period in 2018. The increase was due primarily to a $0.4 million increase in incentive compensation.

General and administrative. General and administrative expenses from continuing operations increased $3.6 million, or 12.3%, to $32.8 million in the three months ended September 30, 2019, from $29.2 million in the same period in 2018. The increase was primarily due to a $3.5 million increase in professional fees related to self-help initiatives.

Transportation. Transportation expenses decreased $8.0 million, or 22%, to $28.4 million in the three months ended September 30, 2019, from $36.4 million in the same period in 2018, in part due to improved management of rail and trucking costs.

Loss on impairment and disposal of assets. Loss on impairment and disposal of assets from continuing operations increased $3.2 million, to $3.2 million in the three months ended September 30, 2019, with no comparable activity in the same period in 2018. This increase was due primarily to $3.6 million impairment recorded for Fluid Holding Corp. (“FHC”), offset by a $0.4 gain from asset disposals. Refer to Note 6 - “Investment in Unconsolidated Affiliates” in Part I, Item 1 “Financial Statements - Notes to Unaudited Condensed Consolidated Financial Statements” for additional information.

Interest expense. Interest expense from continuing operations decreased $3.9 million, or 10.3%, to $33.8 million in the three months ended September 30, 2019, from $37.7 million in the same period in 2018, due to the redemption of our 6.50% Notes due April 2021 (“2021 Notes”) throughout 2019.

Gain (loss) on derivative instruments. There was a $5.0 million loss on derivative instruments in the three months ended September 30, 2019, compared to a $2.7 million loss in the same period in 2018. The change was primarily due to an increase in unrealized losses of $3.0 million, offset by an increase in realized gains of $0.7 million. The increase in unrealized losses was due to a $6.9 million decrease in unrealized gains on crude oil and diesel swaps used to economically hedge purchases and sales driven by market conditions, partially offset by an increase in the unrealized gain of $3.9 million on embedded derivatives associated with our Supply and Offtake Agreements (defined below). The increase in realized gains was primarily related to decreased realized gains on crude oil and diesel swaps during the current quarter.

Net loss from discontinued operations. Net loss from discontinued operations was $0.5 million in three months ended September 30, 2018. In November 2017, we completed the divestiture of Anchor. Prior to being reported as discontinued operations, Anchor was included as its own reportable segment as oilfield services. As a result, effective in the fourth quarter of 2017, we classified our results of operations for all periods presented to reflect Anchor as a discontinued operation. The loss of $0.5 million for the three months ended September 30, 2018 is related to a legal reserve and lease terminations. There was no comparable activity for the three months ended September 30, 2019. Refer to Note 5 - “Discontinued Operations” in Part I, Item 1 “Financial Statements - Notes to Unaudited Condensed Consolidated Financial Statements” for additional information.

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Changes in Results of Operations for the Nine Months Ended September 30, 2019 and 2018

Sales. Sales from continuing operations increased $28.3 million, or 1.1%, to $2,677.8 million in the nine months ended September 30, 2019, from $2,649.5 million in the same period in 2018. Sales for each of our principal product categories in these periods were as follows:



	Nine Months Ended September 30,
	2019		2018		% Change
	(Dollars in millions, except barrel and per barrel data)
Sales by segment:
Specialty products:
Lubricating oils	$	460.7	$	448.3	2.8	%
Solvents	254.2		254.3		—	%
Waxes	92.6		87.8		5.5	%
Packaged and synthetic specialty products ⁽¹⁾	180.2		204.9		(12.1	)%
Other ⁽²⁾	64.7		58.3		11.0	%
Total specialty products	$	1,052.4	$	1,053.6	(0.1	)%
Total specialty products sales volume (in barrels)	7,041,000		6,589,000		6.9	%
Average specialty products sales price per barrel	$	149.47	$	159.90	(6.5	)%

Fuel products:
Gasoline	$	530.9	$	528.8	0.4	%
Diesel	669.4		681.5		(1.8	)%
Jet fuel	100.8		78.9		27.8	%
Asphalt, heavy fuel oils and other ⁽³⁾	324.3		306.7		5.7	%
Total fuel products	$	1,625.4	$	1,595.9	1.8	%
Total fuel products sales volume (in barrels)	22,353,000		19,933,000		12.1	%
Average fuel products sales price per barrel	$	72.72	$	80.06	(9.2	)%

Total sales	$	2,677.8	$	2,649.5	1.1	%
Total specialty and fuel products sales volume (in barrels)	29,394,000		26,522,000		10.8	%


⁽¹⁾	Represents packaged and synthetic specialty products at the Royal Purple, Bel-Ray and Calumet Packaging facilities.


⁽²⁾	Represents (a) by-products, including fuels and asphalt, produced in connection with the production of specialty products at the Princeton and Cotton Valley refineries and Dickinson and Karns City facilities and (b) polyolester synthetic lubricants produced at the Missouri facility.


⁽³⁾	Represents asphalt, heavy fuel oils and other products produced in connection with the production of fuels at the Shreveport, San Antonio and Great Falls refineries and crude oil sales from the San Antonio refinery to third-party customers.

The components of the $1.2 million decrease in specialty products segment sales for the nine months ended September 30, 2019, as compared to the nine months ended September 30, 2018, were as follows:



	Dollar Change
	(In millions)
Volume	72.2
Sales price	(73.4		)
Total specialty products segment sales decrease	$	(1.2	)

Specialty products segment sales decreased $1.2 million period over period, or 0.1%, was primarily due to decreased average selling prices per barrel, the impact of which was almost entirely offset by increased sales volumes. The average selling price per barrel decreased $10.44, resulting in a $73.4 million decrease in sales, driven by an over $9.00 decrease in the average cost of

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crude oil per barrel. The increased sales volumes were the result of improved plant utilization in comparison to the same period in 2018.

The components of the $29.5 million increase in fuel products segment sales for the nine months ended September 30, 2019, as compared to the nine months ended September 30, 2018, were as follows:



	Dollar Change
	(In millions)
Volume	193.7
Sales price	(164.2		)
Total fuel products segment sales increase	$	29.5

Fuel products segment sales increased $29.5 million period over period, or 1.8%, due to increased sales volumes, partially offset by a decrease in the average selling price per barrel. The average selling price per barrel decreased $7.35, or 9.2%, resulting in a $164.2 million decreased in sales, driven by a nearly $6.00 decrease in the average cost of crude oil per barrel. Sales volumes increased 12.1% due to improved plant utilization throughout 2019 in comparison to the same period in 2018, where there was significant downtime.

Gross Profit. Gross profit from continuing operations increased $24.5 million, or 7.3%, to $360.9 million in the nine months ended September 30, 2019, from $335.8 million in the same period in 2018. Gross profit for our specialty and fuel products segments were as follows:



	Nine Months Ended September 30,
	2019			2018			% Change
	(Dollars in millions, except per barrel data)
Gross profit by segment:
Specialty products:
Gross profit	255.6			217.4			17.6	%
Percentage of sales	24.3		%	20.7		%
Specialty products gross profit per barrel	$	36.30		$	32.99		10.0	%
Fuel products:
Gross profit	$	105.3		$	118.4		(11.1	)%
Percentage of sales	6.5		%	7.4		%
Fuel products gross profit per barrel	4.71			5.94			(20.7	)%
Total gross profit	$	360.9		$	335.8		7.5	%
Percentage of sales	13.5		%	12.7		%

The components of the $38.2 million increase in specialty products segment gross profit for the nine months ended September 30, 2019, as compared to the nine months ended September 30, 2018, were as follows:



	Dollar Change
	(In millions)
Nine months ended September 30, 2018 reported gross profit	$	217.4
Sales price	(73.4		)
LIFO inventory layer adjustment	(0.8		)
Operating costs	0.5
LCM inventory adjustment	0.8
Volume	25.5
Cost of Materials	85.6
Nine months ended September 30, 2019 reported gross profit	$	255.6

The increase in specialty products segment gross profit of $38.2 million for the nine months ended September 30, 2019, as compared to the same period in 2018, was primarily due to increased sales volume, partially offset by a modest compression in sales price versus cost of materials. Sales price and cost of materials, net, increased gross profit by $12.2 million, as the average selling price per barrel decreased $10.44, while the average cost of crude oil per barrel decreased over $9.00. The increase in sales

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volume is primarily the result of improved plant utilization in 2019 in comparison to the same period in 2018 where there was significant downtime. The decrease in operating costs was due to lower incentive compensation costs and depreciation and amortization expenses.

The components of the $13.1 million decrease in fuel products segment gross profit for the nine months ended September 30, 2019, as compared to the nine months ended September 30, 2018, were as follows:



	Dollar Change
	(In millions)
Nine months ended September 30, 2018 reported gross profit	$	118.4
Cost of Materials	127.2
Volume	37.6
LCM inventory adjustment	23.2
LIFO inventory layer adjustment	0.3
Operating costs	(1.6		)
RINs expense	(35.6		)
Sales price	(164.2		)
Nine months ended September 30, 2019 reported gross profit	$	105.3

The decrease in fuel products segment gross profit of $13.1 million for the nine months ended September 30, 2019, as compared to the same period in 2018, was primarily the impact from the net, of sales price and cost of materials, which decreased gross profit $37.0 million, an increase in RINs expense and an increase in operating costs, partially offset by an increase in sales volume, and a $23.2 million favorable LCM inventory adjustment in comparison to the same period in 2018. During nine months ended September 30, 2019, the average cost of crude oil per barrel decreased by nearly $6.00, while the average selling price per barrel decreased by $7.35. The increase in RINs expense was due primarily to market pricing and increased plant utilization. Increased volumes were primarily due to improved plant utilization in the nine months ended September 30, 2019 in comparison to the same period in 2018 where there was significant downtime. The $1.6 million increase in operating costs was primarily due to increased incentive compensation costs, partially offset by decreased utilities expenses.

Selling. Selling expenses from continuing operations increased $0.6 million, or 1.5%, to $40.2 million in the nine months ended September 30, 2019, from $39.6 million in the same period in 2018. The increase was driven primarily by a $0.7 million increase in labor and benefits.

General and administrative. General and administrative expenses from continuing operations increased $10.0 million, or 10.5%, to $105.5 million in the nine months ended September 30, 2019, from $95.5 million in the same period in 2018. The increase was primarily due to a $9.3 million increase in professional fees and a $0.6 million increase rental expense .

Loss on impairment and disposal of assets. Loss on impairment and disposal of assets from continuing operations increased $31.1 million, to $31.1 million in the nine months ended September 30, 2019 with no comparable activity in the same period in 2018. This increase was due to impairment charges recorded for the FHC investment and the write-off of the TexStar finance lease asset. Refer to Note 6 - “Investment in Unconsolidated Affiliates” and Note 7 - “Commitments and Contingencies,” respectively, in Part I, Item 1 “Financial Statements - Notes to Unaudited Condensed Consolidated Financial Statements” for additional information.

Other operating (income) expense. Other operating (income) expense from continuing operations decreased $19.5 million, or 104.3%, to expense of $0.8 million in the nine months ended September 30, 2019, from income of $18.7 million in the same period in 2018. The change was primarily due to a 2018 operating income benefit from the reduction of the RINs liability associated with the sale of the Superior Refinery.

Interest expense. Interest expense from continuing operations decreased $21.2 million, or 17.6%, to $99.2 million in the nine months ended September 30, 2019, from $120.4 million in the same period in 2018, primarily due to the redemption of our 6.50% Notes due April 2021 (“2021 Notes”) in 2019 and decreased revolving credit facility borrowings, partially offset by an increase in interest related to the Supply and Offtake Agreements.

Gain (loss) from debt extinguishment. The Company incurred debt extinguishment costs from continuing operations of $58.8 million during the nine months ended September 30, 2018 related to the redemption of the 2021 Secured Notes which were redeemed in April 2018, compared to a gain on debt extinguishment of $0.7 million during the nine months ended September 30, 2019 related to the repurchase of a portion of our 2021 Notes during the period.

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Gain (loss) on derivative instruments. There was a $14.4 million gain on derivative instruments in the nine months ended September 30, 2019, compared to a $2.0 million loss in the same period in 2018. The change was primarily due to a $37.0 million increase in realized gains, partially offset by a $20.6 million increase in unrealized losses. The increase in unrealized losses was primarily due to a $33.2 million increase in unrealized losses on crude oil and diesel swaps used to economically hedge purchases and sales driven by market conditions, partially offset by a decrease in unrealized losses of $13.6 million on embedded derivatives associated with our Supply and Offtake Agreements. The decrease in realized losses was primarily related to settlements of derivative instruments used to economically hedge crack spreads, crude oil and diesel swaps.

Net loss from discontinued operations. Net loss from discontinued operations was $3.1 million in nine months ended September 30, 2018. In November 2017, we completed the divestiture of Anchor. Prior to being reported as discontinued operations, Anchor was included as its own reportable segment as oilfield services. As a result, effective in the fourth quarter of 2017, we classified our results of operations for all periods presented to reflect Anchor as a discontinued operation. The loss of $3.1 million for the nine months ended September 30, 2018 relates to a legal reserve and lease terminations. There was no comparable activity for the nine months ended September 30, 2019. Refer to Note 5 - “Discontinued Operations” in Part I, Item 1 “Financial Statements - Notes to Unaudited Condensed Consolidated Financial Statements” for additional information.

Seasonality

The operating results for the fuel products segment, including the selling prices of asphalt products we produce, generally follow seasonal demand trends. Asphalt demand is generally lower in the first and fourth quarters of the year, as compared to the second and third quarters, due to the seasonality of the road construction and roofing industries we supply. Demand for gasoline and diesel is generally higher during the summer months than during the winter months due to seasonal increases in highway traffic. In addition, our natural gas costs can be higher during the winter months, as demand for natural gas as a heating fuel increases during the winter. As a result, our operating results for the first and fourth calendar quarters may be lower than those for the second and third calendar quarters of each year due to seasonality related to these and other products that we produce and sell.

Liquidity and Capital Resources

General

The following should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources” included under Part II, Item 7 in our 2018 Annual Report. There have been no material changes in that information other than as discussed below. Also, see Note 8 — “Inventory Financing Agreements” and Note 9 — “Long-Term Debt” under Part I, Item 1 “Financial Statements — Notes to Unaudited Condensed Consolidated Financial Statements” in this Quarterly Report for additional discussions related to our Supply and Offtake Agreements and our long-term debt.

Our principal sources of cash have historically included cash flow from operations, proceeds from public equity offerings, proceeds from notes offerings and bank borrowings. Principal uses of cash have included capital expenditures, acquisitions, distributions to our limited partners and general partner and debt service. We may from time to time seek to retire or purchase our outstanding debt through cash purchases and/or exchanges for equity securities, in open market purchases, privately negotiated transactions, tender offers or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

In general, we expect that our short-term liquidity needs including debt service, working capital, replacement and environmental capital expenditures and capital expenditures related to internal growth projects, will be met primarily through projected cash flow from operations, borrowings under our revolving credit facility and asset sales.

Cash Flows from Operating, Investing and Financing Activities

We are subject to business and operational risks that could materially adversely affect our cash flows. A material decrease in our cash flow from operations, including a significant, sudden decrease in crude oil prices, would likely produce a corollary material adverse effect on our borrowing capacity under our revolving credit facility and potentially our ability to comply with the covenants under our revolving credit facility. A significant, sudden increase in crude oil prices, if sustained, would likely result in increased working capital requirements which we expect would be funded by borrowings under our revolving credit facility. In addition, our cash flow from operations may be impacted by the timing of settlement of our derivative activities. Gains and losses from derivative instruments that do not qualify as hedges will impact operating cash flow in the period settled.

The following table summarizes our primary sources and uses of cash in each of the periods presented:

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	Nine Months Ended September 30,
	2019			2018
	(In millions)
Net cash provided by (used in) operating activities	$	153.9		$	(29.3	)
Net cash provided by (used in) investing activities	(13.7		)	13.5
Net cash (used in) financing activities	(131.7		)	(433.0		)
Net increase (decrease) in cash and cash equivalents	$	8.5		$	(448.8	)

Operating Activities. Operating activities provided cash of $153.9 million during the nine months ended September 30, 2019, compared to using cash of $29.3 million during the same period in 2018. The change was impacted by operating cash flow other than working capital adjustments including increased net income from continuing operations of $68.2 million, a $31.1 million increase in the loss on impairment and disposal of assets and a $20.6 million decrease in unrealized gain on derivatives, partially offset by a $26.8 million increase in the favorable LCM inventory adjustment and a increase of $4.0 million in other non-cash activities. Working capital requirements decreased by $154.2 million from the comparative period. The reduction in working capital requirements during the nine months ended September 30, 2019 was primarily driven by positive changes in accounts payable, other liabilities and accrued interest payable in comparison to the same period in 2018.

Investing Activities. Investing activities used cash of $13.7 million during the nine months ended September 30, 2019, compared to providing cash of $13.5 million during the same period in 2018. The change is primarily related to a decrease in net proceeds from the sale of businesses of $44.8 million, offset by a $13.9 million decrease in cash spent on additions to property, plant and equipment as well as an increase of $3.8 million income from unconsolidated affiliates which relates to our investment in Biosynthetic Technologies in the first quarter of 2018.

Financing Activities. Financing activities used cash of $131.7 million in the nine months ended September 30, 2019, compared to using cash of $433.0 million during the same period in 2018. This change is primarily due to the repurchase of $137.3 million of our 2021 Notes during 2019 compared to payments of $446.6 million for the redemption (including debt extinguishment costs) of our 2021 Secured Notes in the same comparative period in 2018.

Investment in Unconsolidated Affiliate

In connection with the Anchor Transaction in November 2017, we received an equity investment in FHC as part of the total consideration for Anchor. FHC provides oilfield services and products to customers globally. Our investment in FHC is a non-marketable equity security without a readily determinable fair value. We record this investment using a measurement alternative which values the security at cost less impairment, if any, plus or minus changes resulting from qualifying observable price changes with a same or similar security from the same issuer.

During the three months ended June 30, 2019, we determined the fair value of our investment in FHC was less than its carrying value of $25.4 million after evaluating indicators of impairment and valuing the investment using projected future cash flows and other Level 3 inputs. Utilizing an income approach, value indications are developed by discounting expected cash flows to their present value at a rate of return that incorporates the risk-free rate for the use of funds, the expected rate of inflation and risks associated with the company. As a result, we recorded an impairment charge of $16.1 million in loss on impairment and disposal of assets in the unaudited condensed consolidated statements of operations for the three months ended June 30, 2019.

During the three months ended September 30, 2019, we determined the fair value of our investment in FHC was less than its carrying value of $9.3 million as a result of a preferred stock issuance by FHC, which diluted our ownership percentage. As a result, we recorded an impairment charge of $3.6 million in loss on impairment and disposal of assets in the unaudited condensed consolidated statements of operations for the three months ended September 30, 2019 and a $19.7 million impairment charge for the nine months ended September 30, 2019.

Supply and Offtake Agreements

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The Supply and Offtake Agreements are subject to minimum and maximum inventory levels. The agreements also provide for the lease to Macquarie of crude oil and certain refined product storage tanks located at the Great Falls and Shreveport refineries. Following expiration or termination of the agreements, Macquarie has the option to require us to purchase the crude oil and refined product inventories then owned by Macquarie and located at the leased storage tanks at then current market prices. Our obligations under the agreements are secured by the inventory included in these agreements.

Capital Expenditures

Our property, plant and equipment capital expenditure requirements consist of capital improvement expenditures, replacement capital expenditures, environmental capital expenditures and turnaround capital expenditures. Capital improvement expenditures include expenditures to acquire assets to grow our business, to expand existing facilities, such as projects that increase operating capacity, or to reduce operating costs. Replacement capital expenditures replace worn out or obsolete equipment or parts. Environmental capital expenditures include asset additions to meet or exceed environmental and operating regulations. Turnaround capital expenditures represent capitalized costs associated with our periodic major maintenance and repairs.

The following table sets forth our capital improvement expenditures, replacement capital expenditures, environmental capital expenditures and turnaround capital expenditures in each of the periods shown (including capitalized interest):



	Nine Months Ended September 30,
	2019		2018
	(In millions)
Capital improvement expenditures	$	10.1	$	17.3
Replacement capital expenditures	15.2		9.5
Environmental capital expenditures	11.8		6.5
Turnaround capital expenditures	16.8		21.8
Total	$	53.9	$	55.1

Biosyn Holdings, LLC and Biosynthetic Technologies

In February 2018, the Company and The Heritage Group formed Biosyn for the purpose of acquiring Biosynthetic Technologies, LLC, a startup company which developed an intellectual property portfolio for the manufacture of renewable-based and biodegradable esters. In March 2019, the Company sold its investment in Biosyn to The Heritage Group, a related party, for total proceeds of $5.0 million, which was recorded in the “other” component of other income (expense) on the unaudited condensed consolidated statement of operations. Prior to the sale of Biosyn, the Company accounted for its ownership in Biosyn under the equity method of accounting.

2019 Capital Spending Forecast

We have a turnaround at the Shreveport refinery in the fourth quarter of 2019. We have expanded the scope of the turnaround with the objective of avoiding any planned downtime of this facility in 2020 in an effort to capture any improvement in ULSD cracks caused by IMO 2020. As a result, we estimate our capital expenditures will be within the previously guided range of $80.0 million and $90.0 million in 2019, but will likely not be near the low end of the range. We anticipate that capital expenditure requirements will be provided primarily through cash flow from operations, cash on hand, available borrowings under our revolving credit facility and by accessing capital markets as necessary. If future capital expenditures require expenditures in excess of our then-current cash flow from operations and borrowing availability under our existing revolving credit facility, we may be required to issue debt or equity securities in public or private offerings or incur additional borrowings under bank credit facilities to meet those costs.

Debt and Credit Facilities

As of September 30, 2019, our primary debt and credit instruments consisted of the following:


•	$600.0 million senior secured revolving credit facility maturing in February 2023 (“revolving credit facility”);

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•	$761.2 million of 6.50% senior notes due 2021 (“2021 Notes”);


•	$350.0 million of 7.625% senior notes due 2022 (“2022 Notes”); and


•	$325.0 million of 7.75% senior notes due 2023 (“2023 Notes”).

We were in compliance with all covenants under the debt instruments in place as of September 30, 2019 and believe we have adequate liquidity to conduct our business.

Short-Term Liquidity

As of September 30, 2019, our principal sources of short-term liquidity were (i) $273.5 million of availability under our revolving credit facility, (ii) inventory financing agreements related to the Great Falls and Shreveport refineries and (iii) $164.2 million of cash on hand. Borrowings under our revolving credit facility can be used for, among other things, working capital, capital expenditures and other lawful partnership purposes including acquisitions.

On February 23, 2018, we entered into the Third Amended and Restated Credit Agreement (the "Credit Agreement"), which provided for our $600.0 million senior secured revolving credit facility maturing in February 2023. The revolving credit facility is subject to borrowing base limitation, with a maximum letter of credit sublimit of $300.0 million, which amount may be increased to 90% of revolver commitments in effect with the consent of the Agent.

On September 4, 2019, we entered into the First Amendment (the “First Amendment”) to the Credit Agreement. The amendment expands the borrowing base by $99.6 million on the Effective Date (as defined in the amendment) by adding the fixed assets of our Great Falls, MT refinery as collateral to the borrowing base. The $99.6 million expansion amortizes to zero on a straight-line basis over ten quarters starting in the first quarter of 2020. Additionally, while the fixed assets of the Great Falls, MT refinery are included in the borrowing base, the First Amendment provides for a 25 basis points increase in the applicable margin for loans, as well as increases in the minimum availability under the revolving credit facility required for us to be able to perform certain actions, including to make restricted payments of other distributions, sell or dispose of certain assets, make acquisitions or investments, or prepay other indebtedness. Among other conditions precedent that were required to be satisfied before the Effective Date, we were required to consummate an offering of at least $450.0 million aggregate principal amount of senior unsecured notes. The conditions precedent were not satisfied until October 11, 2019. Therefore, the $99.6 million expansion was not in effect as of September 30, 2019. Please read Note 15 - “Subsequent Events” for additional information.

Borrowings under the revolving credit facility are limited to a borrowing base that is determined based on advance rates of percentages of Eligible Accounts and Eligible Inventory (each as defined in the revolving credit agreement). As such, the borrowing base can fluctuate based on changes in selling prices of our products and our current material costs, primarily the cost of crude oil. The borrowing base is calculated in accordance with the revolving credit facility and agreed upon by us and the Agent (as defined in the revolving credit facility agreement). On September 30, 2019, we had availability on our revolving credit facility of approximately $273.5 million, based on a borrowing base of approximately $343.6 million, $70.1 million in outstanding standby letters of credit and no outstanding borrowings. The borrowing base cannot exceed the revolving credit facility commitments then in effect. The lender group under our revolving credit facility is comprised of a syndicate of nine lenders with total commitments of $600.0 million. The lenders under our revolving credit facility have a first priority lien on our accounts receivable, certain inventory and substantially all of our cash.

Amounts outstanding under our revolving credit facility can fluctuate materially during each quarter mainly due to cash flow from operations, normal changes in working capital, capital expenditures and debt service costs. Specifically, the amount borrowed under our revolving credit facility is typically at its highest level after we pay for the majority of our crude oil supply on the 20th day of every month per standard industry terms. During the quarter ended September 30, 2019, we did not have any borrowings under the revolving credit facility. Our availability under our revolving credit facility during the peak borrowing days of the quarter has been sufficient to support our operations and service upcoming requirements. During the quarter ended September 30, 2019, availability for additional borrowings under our revolving credit facility was approximately $259.7 million at its lowest point.

The revolving credit facility currently bears interest at a rate equal to prime plus an applicable margin, or LIBOR plus an applicable margin, at our option, which applicable margin ranges between 50 basis points and 100 basis points for base rate loans and 150 basis points to 200 basis points for LIBOR loans, depending on our average availability for additional borrowings for the preceding quarter. The margin applicable to loans under the first loaned in and last to be repaid out (“FILO”) tranche of the revolving credit facility range from 150 to 200 basis points for base rate FILO loans and 250 to 300 basis points for LIBOR based FILO loans. The credit agreement provides for a 25 basis point reduction in the applicable margin rates beginning in the quarter after our Leverage Ratio (as defined in the credit agreement) is less than 5.5 to 1.0. As we met this test in fiscal quarter ended June 30, 2019, our applicable margin for the quarter ended, and including, September 30, 2019 was 25 basis points for prime, 125 basis points for LIBOR, 125 basis points for prime rate based FILO loans and 225 basis points for LIBOR based FILO loans; however, the margin can fluctuate quarterly based on our average availability for additional borrowings under the revolving credit facility in the preceding calendar quarter. Letters of credit issued under the revolving credit facility accrue fees at a rate equal to the margin (measured in basis points) applicable to the LIBOR revolver loans.

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In addition to paying interest on outstanding borrowings under the revolving credit facility, we are 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 either 0.250% or 0.375% per annum, depending on the average daily available unused borrowing capacity for the preceding month. We also pay 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.

Our revolving credit facility contains various covenants that limit, among other things, our 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. The revolving credit facility generally permits us to make cash distributions to our unitholders as long as, after giving effect to each such cash distribution, we have availability under the revolving credit facility and cash on hand totaling at least equal to the sum of the amount of FILO Loans outstanding plus the greater of (i) 15% of the Aggregate Borrowing Base (as defined in the revolving credit facility agreement) then in effect, or 25% while the Great Falls, MT refinery is included in the borrowing base, and (ii) $60.0 million (which amount is subject to increase in proportion to revolving commitment increases). Further, the revolving credit facility contains one springing financial covenant: if the availability of loans under the revolving credit facility falls below the sum of the amount of FILO loans outstanding plus the greater of (i) 10% of the Aggregate Borrowing Base, or 15% while the Great Falls, MT refinery is included in the borrowing base, and (ii) $35.0 million (which amount is subject to increase in proportion to revolving commitment increases), we will be required to maintain as of the end of each fiscal quarter a Fixed Charge Coverage Ratio (as defined in the revolving credit facility agreement) of at least 1.0 to 1.0.

If an event of default exists under the revolving credit facility, the lenders will be able to accelerate the maturity of the credit facility and exercise other rights and remedies. An event of default includes, among other things, the nonpayment of principal, interest, fees or other amounts; failure of any representation or warranty to be true and correct when made or confirmed; failure to perform or observe covenants in the revolving credit facility or other loan documents, subject, in limited circumstances, to certain grace periods; cross-defaults in other indebtedness if the effect of such default is to cause, or permit the holders of such indebtedness to cause, the acceleration of such indebtedness under any material agreement; bankruptcy or insolvency events; monetary judgment defaults; asserted invalidity of the loan documentation; and a Change of Control (as defined in the revolving credit facility agreement).

For additional information regarding our revolving credit facility, see Note 9 - “Long-Term Debt” under Part I, Item 1 “Financial Statements — Notes to Unaudited Condensed Consolidated Financial Statements” in this Quarterly Report.

Long-Term Financing

In addition to our principal sources of short-term liquidity listed above, subject to market conditions, we may meet our cash requirements (other than distributions of Available Cash (as defined in our partnership agreement) to our common unitholders) through the issuance of long-term notes or additional common units.

From time to time we issue long-term debt securities, referred to as our senior notes. All of our outstanding senior notes are unsecured obligations that rank equally with all of our other senior debt obligations to the extent they are unsecured. As of September 30, 2019, we had $761.2 million in 2021 Notes, $350.0 million in 2022 Notes and $325.0 million in 2023 Notes outstanding. As of December 31, 2018, we had $900.0 million in 2021 Notes, $350.0 million in 2022 Notes and $325.0 million in 2023 Notes outstanding.

During the three months ended September 30, 2019, we repurchased $49.0 million aggregate principal amount of our 2021 Notes at an average price of 99.4% of par value, plus accrued and unpaid interest thereon up to, but not including the respective transaction dates. In conjunction with the repurchases during the three months ended September 30, 2019, we recorded no gain or loss from debt extinguishment.

As of September 30, 2019, we had repurchased $138.8 million aggregate principal amount of our 2021 Notes and the remaining principal amount following these repurchases was $761.2 million. During the nine months ended September 30, 2019, we recorded a net gain from debt extinguishment of $0.7 million. For more information regarding the repurchases of our 2021 Notes, see Note 9 - “Long-Term Debt” under Part I, Item 1 “Financial Statements - Notes to Unaudited Condensed Consolidated Financial Statements” in this Quarterly Report.

On October 11, 2019, we issued and sold $550.0 million aggregate principal amount of 11.00% Senior Notes due 2025 at par. We received net proceeds of $540.0 million net of initial purchasers’ discounts and estimated expenses. We used the net proceeds along with revolver borrowings and cash on hand to fund the redemption of the 2021 Notes.

On October 21, 2019, we redeemed at par $761.2 million aggregate principal amount outstanding of the remaining 2021 Notes issued in March 2014 with the net proceeds from the issuance of the 2025 Notes, together with borrowings under our revolving credit facility and cash on hand, at a redemption price of $761.2 million, plus accrued and unpaid interest.

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The indentures governing our senior notes contain covenants that, among other things, restrict our ability and the ability of certain of our subsidiaries to: (i) sell assets; (ii) pay distributions on, redeem or repurchase our common units or redeem or repurchase our 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 our restricted subsidiaries to us; (vii) consolidate, merge or transfer all or substantially all of our 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 senior notes are rated investment grade by either Moody’s Investors Service, Inc. (“Moody’s”) or S&P Global Ratings (“S&P”) and no Default or Event of Default, each as defined in the indentures governing the senior notes, has occurred and is continuing, many of these covenants will be suspended. As of September 30, 2019, our Fixed Charge Coverage Ratio (as defined in the indentures governing the 2021 Notes, 2022 Notes and 2023 Notes) was 2.3.

Upon the occurrence of certain change of control events, each holder of the senior notes will have the right to require that we repurchase all or a portion of such holder’s senior notes in cash at a purchase price equal to 101% of the principal amount thereof, plus any accrued and unpaid interest to the date of repurchase.

We are subject, however, to conditions in the equity and debt markets for our common units and long-term senior notes, and there can be no assurance we will be able or willing to access the public or private markets for our common units and/or senior notes in the future. If we are unable or unwilling to issue additional common units, we may be required to either restrict capital expenditures and/or potential future acquisitions or pursue debt financing alternatives, some of which could involve higher costs or negatively affect our credit ratings. Furthermore, our ability to access the public and private debt markets is affected by our credit ratings.

For additional information regarding our senior notes, see Note 9 — “Long-Term Debt” under Part I, Item 1 “Financial Statements — Notes to Unaudited Condensed Consolidated Financial Statements” in this Quarterly Report and Note 9 — “Long-Term Debt” in Part II, Item 8 “Financial Statements and Supplementary Data” of our 2018 Annual Report.

Master Derivative Contracts and Collateral Trust Agreement

Under our credit support arrangements, our payment obligations under all of our master derivatives contracts for commodity hedging generally are secured by a first priority lien on our and our subsidiaries’ real property, plant and equipment, fixtures, intellectual property, certain financial assets, certain investment property, commercial tort claims, chattel paper, documents, instruments and proceeds of the foregoing (including proceeds of hedge arrangements). We had no additional letters of credit or cash margin posted with any hedging counterparty as of September 30, 2019. Our master derivatives contracts continue to impose a number of covenant limitations on our operating and financing activities, including limitations on liens on collateral, limitations on dispositions of collateral and collateral maintenance and insurance requirements. For financial reporting purposes, we do not offset the collateral provided to a counterparty against the fair value of our obligation to that counterparty. Any outstanding collateral is released to us upon settlement of the related derivative instrument liability.

All credit support thresholds with our hedging counterparties are at levels such that it would take a substantial increase in fuel products crack spreads or interest rates to require significant additional collateral to be posted. As a result, we do not expect further increases in fuel products crack spreads or interest rates to significantly impact our liquidity.

Additionally, we have a collateral trust agreement (the “Collateral Trust Agreement”) which governs how secured hedging counterparties share collateral pledged as security for the payment obligations owed by us to the secured hedging counterparties under their respective master derivatives contracts. The Collateral Trust Agreement limits to $150.0 million the extent to which forward purchase contracts for physical commodities are covered by, and secured under, the Collateral Trust Agreement and the Parity Lien Security Documents (as defined in the Collateral Trust Agreement). There is no such limit on financially settled derivative instruments used for commodity hedging. Subject to certain conditions set forth in the Collateral Trust Agreement, we have the ability to add secured hedging counterparties from time to time.

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Contractual Obligations and Commercial Commitments

A summary of our total contractual cash obligations as of September 30, 2019, at current maturities and reflecting only those line items that have materially changed since December 31, 2018, is as follows:



			Payments Due by Period
	Total		Less Than 1 Year		1–3 Years		3–5 Years		More Than 5 Years
	(In millions)
Operating activities:
Interest on long-term debt at contractual rates and maturities ⁽¹⁾	$	275.8	$	104.9	$	144.4	$	26.4	$	0.1
Operating lease obligations ⁽²⁾	122.1		67.7		38.2		12.4		3.8
Letters of credit ⁽³⁾	70.1		70.1		—		—		—
Purchase commitments ⁽⁴⁾	389.8		217.5		66.9		50.4		55.0
Employment agreements ⁽⁵⁾	1.6		1.0		0.6		—		—
Financing activities:
Obligations under inventory financing agreements	117.6		117.6		—		—		—
Finance lease obligations	2.8		0.3		0.6		0.8		1.1
Long-term debt obligations, excluding finance lease obligations	1,440.3		123.2		992.1		325.0		—
Total obligations	$	2,420.1	$	702.3	$	1,242.8	$	415.0	$	60.0


⁽¹⁾	Interest on long-term debt at contractual rates and maturities relates primarily to interest on our senior notes, revolving credit facility interest and fees and interest on our finance lease obligations, which excludes the adjustment for the interest rate swap agreement.


⁽²⁾	We have various operating leases primarily for railcars, the use of land, storage tanks, compressor stations, equipment, precious metals and office facilities that extend through September 2034.


⁽³⁾	Letters of credit primarily supporting crude oil and other feedstock purchases.


⁽⁴⁾	Purchase commitments consist primarily of obligations to purchase fixed volumes of crude oil, other feedstocks and finished products for resale from various suppliers based on current market prices at the time of delivery.


⁽⁵⁾	Certain employment agreements may be terminated under certain circumstances or at certain dates prior to expiration. We expect our contracts will be renewed or replaced with similar agreements upon their expiration. Amounts due under the contracts assume the contracts are not terminated prior to their expiration.

For additional information regarding our expected capital and turnaround expenditures for the remainder of 2019, for which we have not contractually committed, refer to “Capital Expenditures” above.

Off-Balance Sheet Arrangements

We did not enter into any material off-balance sheet debt transactions during the three and nine months ended September 30, 2019.

Critical Accounting Policies and Estimates

For additional discussion regarding our critical accounting policies and estimates, see “Critical Accounting Policies and Estimates” under Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our 2018 Annual Report. There have been no material changes to such policies that occurred during the quarterly period ended September 30, 2019.

Recent Accounting Pronouncements

For additional discussion regarding recent accounting pronouncements, see Note 2 — “New Accounting Pronouncements” under Part I, Item 1 “Financial Statements — Notes to Unaudited Condensed Consolidated Financial Statements.”

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

The following should be read in conjunction with “Quantitative and Qualitative Disclosures About Market Risk” included under Part II, Item 7A in our 2018 Annual Report. There have been no material changes in that information other than as discussed below. Also, see Note 10 — “Derivatives” under Part I, Item 1 “Financial Statements — Notes to Unaudited Condensed Consolidated Financial Statements” in this Quarterly Report for additional discussion related to derivative instruments and hedging activities.

Commodity Price Risk

Derivative Instruments

We are exposed to price risks due to fluctuations in the price of crude oil, refined products (primarily in our fuel products segment), natural gas and precious metals. We use various strategies to reduce our exposure to commodity price risk. We do not attempt to eliminate all of our risk as the costs of such actions are believed to be too high in relation to the risk posed to our future cash flows, earnings and liquidity. The strategies we use to reduce our risk utilize both physical forward contracts and financially settled derivative instruments, such as swaps, collars, options and futures, to attempt to reduce our exposure with respect to:


•	crude oil purchases and sales;


•	refined product sales and purchases;


•	natural gas purchases;


•	precious metals; and


•	fluctuations in the value of crude oil between geographic regions and between the different types of crude oil such as NYMEX WTI, Light Louisiana Sweet, WCS, WTI Midland, Mixed Sweet Blend and ICE Brent.

Please read Note 10 — “Derivatives” in the notes to our unaudited condensed consolidated financial statements under Part I, Item 1 “Financial Statements — Notes to Unaudited Condensed Consolidated Financial Statements” for a discussion of the accounting treatment for the various types of derivative instruments, for a further discussion of our hedging policies and for more information relating to our implied crack spreads of crude oil, diesel, and gasoline derivative instruments.

Our derivative instruments and overall specialty products segment and fuel products segment hedging positions are monitored regularly by our risk management committee, which includes executive officers. The risk management committee reviews market information and our hedging positions regularly to determine if additional derivatives activity is advised. A summary of derivative positions and a summary of hedging strategy are presented to our general partner’s Board of Directors quarterly.

Compliance Price Risk

Renewable Identification Numbers

We are exposed to market risks related to the volatility in the price of credits needed to comply with governmental programs. 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, we are required to blend biofuels into the fuel products we produce at a rate that will meet the EPA’s annual quota. To the extent we are unable to blend biofuels at that rate or receive hardship exemptions, we must purchase RINs in the open market to satisfy the annual requirement. We have not entered into any derivative instruments to manage this risk, but we have purchased RINs when the price of these instruments is deemed favorable.

Holding other variables related to RINs requirements constant, a $1.00 increase in the price of RINs as of September 30, 2019, would be expected to have a negative impact on net income for 2019 of approximately $50.3 million.

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Interest Rate Risk

Our exposure to interest rate changes on fixed rate debt is limited to the fair value of the debt issued, which would not have a material impact on our earnings or cash flows. The following table provides information about the fair value of our fixed rate debt obligations as of September 30, 2019 and December 31, 2018, which we disclose in Note 9 — “Long-Term Debt” and Note 11 — “Fair Value Measurements” under Part I, Item 1 “Financial Statements — Notes to Unaudited Condensed Consolidated Financial Statements.”



	September 30, 2019				December 31, 2018
	Fair Value		Carrying Value		Fair Value		Carrying Value
	(In millions)
Financial Instrument:
2021 Notes	$	762.2	$	758.3	$	755.7	$	894.7
2022 Notes	$	336.0	$	346.8	$	279.4	$	345.9
2023 Notes	$	302.2	$	320.8	$	252.3	$	320.1

For our variable rate debt, if any, changes in interest rates generally do not impact the fair value of the debt instrument but may impact our future earnings and cash flows. We had a $600.0 million revolving credit facility as of September 30, 2019, with borrowings bearing interest at the prime rate or LIBOR, at our option, plus the applicable margin. Borrowings under this facility are variable. We had no outstanding variable rate debt as of September 30, 2019 and December 31, 2018.

Foreign Currency Risk

We have minimal exposure to foreign currency risk and as such the cost of hedging this risk is viewed to be in excess of the benefit of further reductions in our exposure to foreign currency exchange rate fluctuations.

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Item 4. Controls and Procedures

(a) Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Quarterly Report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were not effective as of September 30, 2019, at the reasonable assurance level due to material weaknesses in our internal controls as described below.

As of September 30, 2019, the following material weaknesses existed:

•

The ineffective design and implementation of effective controls with respect to the implementation of our enterprise resource planning (“ERP”) system consistent with our financial reporting requirements. Specifically, management did not design effective controls over the ERP implementation to ensure appropriate data conversion and data integrity or provide sufficient end user training to our employees to ensure that our employees could effectively operate the system and carry out their responsibilities.


•	The untimely and insufficient operation of controls in the financial statement close process, including lack of timely account reconciliation, analysis and review related to all financial statement accounts.

These material weaknesses resulted in not having adequate automated and manual controls designed and in place and not achieving the intended operating effectiveness of those controls, which impacted all financial statement accounts and disclosures.

Given the material weaknesses that existed as of September 30, 2019, we concluded that internal control over financial reporting remained ineffective as of September 30, 2019.

Planned Remediation Efforts to Address Existing Material Weaknesses

Ineffective design and implementation of ERP controls - Management completed the remediation plans around data integrity and conversion during the second quarter of 2019 and is testing those controls during the remainder of 2019. Those remediation efforts involved the following:

•

We implemented certain additional controls around data management and review to ensure accurate data integrity and change controls, including but not limited to, centralizing the data management function and implementing change controls. As we test the controls around data management, we may make additional changes to our processes or controls to ensure adequate remediation of the material weakness.


•	We reinforced the importance of our control environment across the Company, we provided additional training to employees to enhance their understanding of processes so they can effectively operate the system and perform the related controls. This training is ongoing and continues to be enhanced.

Financial statement close process - We continue to progress in the execution of our remediation plans associated with the financial statement close process and are committed to improving our internal controls and processes. These remediation plans include, but are not limited to the following:


•	Reviewing , analyzing and properly documenting our processes related to internal controls over financial reporting.


•	Continuing to design and implement effective review and approval controls. These controls will address the accuracy and completeness of the data used in the performance of the respective controls.

When fully implemented and operational, we believe the measures described above will remediate the control deficiencies that led to the material weaknesses and strengthen our internal controls over financial reporting. As we continue to evaluate and work to improve our internal controls over financial reporting, we may take additional measures to address control deficiencies or modify certain activities of the remediation measures described above.

Changes in Internal Control over Financial Reporting

As described above, we have undertaken remediation actions to address the material weaknesses in our internal control over financial reporting. These remediation actions continued throughout the quarter ended September 30, 2019 but have not materially affected our internal control over financial reporting.

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With the exception of the foregoing remediation actions and the changes described in the previous section, there have been no changes in our internal control over financial reporting during the period covered by this Quarterly Report that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

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PART II

Item 1. Legal Proceedings

We are not a party to, and our property is not the subject of, any pending legal proceedings other than ordinary routine litigation incidental to our business. Our operations are subject to a variety of risks and disputes normally incidental to our business. As a result, we may, at any given time, be a defendant in various legal proceedings and litigation arising in the ordinary course of business. The information provided under Note 7 — “Commitments and Contingencies” in Part I, Item 1 “Financial Statements — Notes to Unaudited Condensed Consolidated Financial Statements” is incorporated herein by reference.

Item 1A. Risk Factors

In addition to the other information set forth in this Quarterly Report, you should carefully consider the risks discussed in Part I, Item 1A “Risk Factors” in our 2018 Annual Report and Part II, Item 1A “Risk Factors” in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2019. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results. There have been no material changes in the risk factors discussed in Part I, Item 1A “Risk Factors” in our 2018 Annual Report and Part II, Item 1A “Risk Factors” in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2019.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

Not applicable.

Item 6. Exhibits



Exhibit Number		Description

3.1		Certificate of Limited Partnership of Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Registrant’s Registration Statement on Form S-1 filed with the Commission on October 7, 2005 (File No. 333-128880)).

3.2		Amended and Restated Limited Partnership Agreement of Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on February 13, 2006 (File No. 000-51734)).

3.3		Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on July 11, 2006 (File No. 000-51734)).

3.4		Amendment No. 2 to First Amended and Restated Agreement of Limited Partnership of Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on April 18, 2008 (File No. 000-51734)).

3.5		Amendment No. 3 to First Amended and Restated Agreement of Limited Partnership of Calumet Specialty Products Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on January 4, 2018 (File No. 000-51734)).

3.6		Certificate of Formation of Calumet GP, LLC (incorporated by reference to Exhibit 3.3 of Registrant’s Registration Statement on Form S-1 filed with the Commission on October 7, 2005 (File No. 333-128880)).

3.7		Amended and Restated Limited Liability Company Agreement of Calumet GP, LLC (incorporated by reference to Exhibit 3.2 to the Registrant’s Current Report on Form 8-K filed with the Commission on February 13, 2006 (File No. 000-51734)).

4.1*		Sixth Supplemental Indenture and Amendment, dated September 27, 2019, by and among Calumet Specialty Products Partners, L.P., Calumet Finance Corp., certain subsidiary guarantors named therein and Wilmington Trust, National Association, as trustee.

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Exhibit Number		Description
4.2*		Second Supplemental Indenture and Amendment, dated September 27, 2019, by and among Calumet Specialty Products Partners, L.P., Calumet Finance Corp., certain subsidiary guarantors named therein and Wilmington Trust, National Association, as trustee.

4.3		Indenture, dated October 11, 2019, by and among Calumet Specialty Products Partners, L.P., Calumet Finance Corp., certain subsidiary guarantors named therein and Wilmington Trust, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Registrant’s Form 8-K filed with the Commission on October 11, 2019 (File No. 000-51734)).

10.1		First Amendment to Credit Agreement, dated September 4, 2019, by and among Calumet Specialty Products Partners, L.P., Bank of America, N.A., and the other parties signatory thereto (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on September 6, 2019 (File No. 000-51734)).

31.1*		Sarbanes-Oxley Section 302 certification of Timothy Go.

31.2*		Sarbanes-Oxley Section 302 certification of D. West Griffin.

32.1**		Section 1350 certification of Timothy Go and D. West Griffin.

100.INS*		XBRL Instance Document

101.SCH*		XBRL Taxonomy Extension Schema Document

101.CAL*		XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF*		XBRL Taxonomy Extension Definition Linkbase Document

101.LAB*		XBRL Taxonomy Extension Label Linkbase Document

101.PRE*		XBRL Taxonomy Extension Presentation Linkbase Document

*		Filed herewith.
**		Furnished herewith.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.



		CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.

		By:	Calumet GP, LLC, its general partner

Date:	November 12, 2019	By:	/s/ D. West Griffin
			D. West Griffin
			Executive Vice President and Chief Financial Officer
			(Authorized Person and Principal Accounting Officer)