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Calumet Specialty Products Partners, L.P. - Quarter Report: 2018 June (Form 10-Q)

Table of Contents

 
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 JUNE 30, 2018
OR
☐
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 Officers)
 
(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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Registration S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post 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.
Large accelerated filer
 
☐
 
Accelerated filer
 
☒
Non-accelerated filer
 
☐ (Do not check if a smaller reporting company)
 
Smaller reporting company
 
☐
Emerging growth company
 
☐
 
 
 
 
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  ☒
On August 9, 2018, there were 77,099,282 common units outstanding.
 

Table of Contents

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
QUARTERLY REPORT
For the Three and Six Months Ended June 30, 2018
Table of Contents
 
 
Page
 

2
Table of Contents

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 and (viii) the future effectiveness of our new enterprise resource planning (“ERP”) system to further enhance operating efficiencies and provide more effective management of our business operations, 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 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 II, Item 7A “Quantitative and Qualitative Disclosures About Market Risk” and Part I, Item 1A “Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended December 31, 2017 (“2017 Annual Report”), (ii) Part II, Item 1A “Risk Factors” in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2018 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.




3
Table of Contents

PART I
Item 1. Financial Statements
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
CONDENSED CONSOLIDATED BALANCE SHEETS
 
June 30, 2018
 
December 31, 2017
 
(Unaudited)
 
 
 
(In millions, except unit data)
ASSETS
Current assets:
 
 
 
Cash and cash equivalents
$
38.8

 
$
164.3

Restricted cash
—

 
350.0

Accounts receivable, net:
 
 
 
Trade
269.9

 
265.4

Other
32.5

 
88.7

 
302.4

 
354.1

Inventories
334.1

 
314.4

Derivative assets
3.8

 
—

Prepaid expenses and other current assets
10.0

 
8.7

Total current assets
689.1

 
1,191.5

Property, plant and equipment, net
1,135.5

 
1,159.2

Investment in unconsolidated affiliates
25.4

 
35.0

Goodwill
171.4

 
171.4

Other intangible assets, net
97.9

 
107.9

Other noncurrent assets, net
25.2

 
23.8

Total assets
$
2,144.5

 
$
2,688.8

LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
 
 
 
Accounts payable
$
257.9

 
$
282.3

Accrued interest payable
30.8

 
52.5

Accrued salaries, wages and benefits
30.1

 
35.9

Other taxes payable
21.3

 
16.1

Obligations under inventory financing agreements
108.1

 
103.1

Other current liabilities
22.3

 
73.7

Current portion of long-term debt
2.9

 
354.1

Derivative liabilities
0.1

 
6.0

Discontinued operations, current liabilities
0.3

 
2.0

Total current liabilities
473.8

 
925.7

Pension and postretirement benefit obligations
3.0

 
3.1

Other long-term liabilities
1.5

 
1.9

Long-term debt, less current portion
1,599.6

 
1,638.2

Total liabilities
2,077.9

 
2,568.9

Commitments and contingencies
 
 
 
Partners’ capital:
 
 
 
Limited partners’ interest 77,081,069 units and 76,788,801 units, issued and outstanding as of June 30, 2018 and December 31, 2017, respectively
58.9

 
113.3

General partner’s interest
12.7

 
13.8

Accumulated other comprehensive loss
(5.0
)
 
(7.2
)
Total partners’ capital
66.6

 
119.9

Total liabilities and partners’ capital
$
2,144.5

 
$
2,688.8

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 June 30,
 
Six Months Ended June 30,
 
2018
 
2017
 
2018
 
2017
 
(In millions, except per unit and unit data)
Sales
$
945.5

 
$
967.0

 
$
1,696.0

 
$
1,853.5

Cost of sales
822.1

 
823.3

 
1,459.4

 
1,580.3

Gross profit
123.4

 
143.7

 
236.6

 
273.2

Operating costs and expenses:
 
 
 
 
 
 
 
Selling
10.6

 
15.1

 
25.3

 
31.4

General and administrative
31.9

 
32.4

 
72.5

 
63.0

Transportation
33.0

 
35.6

 
63.3

 
71.3

Taxes other than income taxes
5.4

 
4.8

 
7.3

 
10.0

Asset impairment
—

 
—

 
—

 
0.4

Other operating (income) expense
(1.1
)
 
1.1

 
(16.7
)
 
3.0

Operating income
43.6

 
54.7

 
84.9

 
94.1

Other income (expense):
 
 
 
 
 
 
 
Interest expense
(37.5
)
 
(44.5
)
 
(82.7
)
 
(88.4
)
Debt extinguishment costs
(58.2
)
 
—

 
(58.8
)
 
—

Gain on derivative instruments
0.8

 
1.3

 
0.7

 
7.0

Other
0.9

 
0.5

 
2.4

 
0.7

Total other expense
(94.0
)
 
(42.7
)
 
(138.4
)
 
(80.7
)
Net income (loss) from continuing operations before income taxes
(50.4
)
 
12.0

 
(53.5
)
 
13.4

Income tax expense (benefit) from continuing operations
0.8

 
—

 
0.6

 
(0.1
)
Net income (loss) from continuing operations
$
(51.2
)
 
$
12.0

 
$
(54.1
)
 
$
13.5

Net loss from discontinued operations, net of tax
$
(0.7
)
 
$
(2.4
)
 
$
(2.6
)
 
$
(10.1
)
Net income (loss)
$
(51.9
)
 
$
9.6

 
$
(56.7
)
 
$
3.4

Allocation of net income (loss):
 
 
 
 
 
 
 
Net income (loss)
$
(51.9
)
 
$
9.6

 
$
(56.7
)
 
$
3.4

Less:
 
 
 
 
 
 
 
General partner’s interest in net income (loss)
(1.0
)
 
0.2

 
(1.1
)
 
0.1

Non-vested share based payments
—

 
0.2

 
—

 
0.2

Net income (loss) available to limited partners
$
(50.9
)
 
$
9.2

 
$
(55.6
)
 
$
3.1

Weighted average limited partner units outstanding:
 
 
 
 
 
 
 
Basic
77,730,458

 
77,554,815

 
77,644,262

 
77,485,058

Diluted
77,730,458

 
77,714,112

 
77,644,262

 
77,725,656

Limited partners’ interest basic and diluted net income (loss) per unit:
 
 
 
 
 
 
 
From continuing operations
$
(0.64
)
 
$
0.15

 
$
(0.68
)
 
$
0.17

From discontinued operations
(0.01
)
 
(0.03
)
 
(0.03
)
 
(0.13
)
Limited partners’ interest
$
(0.65
)
 
$
0.12

 
$
(0.71
)
 
$
0.04

See accompanying notes to unaudited condensed consolidated financial statements.

5
Table of Contents

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2018
 
2017
 
2018
 
2017
 
(In millions)
Net income (loss)
$
(51.9
)
 
$
9.6

 
$
(56.7
)
 
$
3.4

Other comprehensive income:
 
 
 
 
 
 
 
Cash flow hedges:
 
 
 
 
 
 
 
Cash flow hedge loss reclassified to net loss
2.1

 
—

 
2.1

 
—

Defined benefit pension and retiree health benefit plans
0.1

 
—

 
0.1

 
—

Total other comprehensive income
2.2

 
—

 
2.2

 
—

Comprehensive income (loss) attributable to partners’ capital
$
(49.7
)
 
$
9.6

 
$
(54.5
)
 
$
3.4

See accompanying notes to unaudited condensed consolidated financial statements.


6
Table of Contents

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
 
Accumulated Other
Comprehensive Loss
 
Partners’ Capital
 
 
 
 
General
Partner
 
Limited
Partners
 
Total
 
(In millions)
Balance at December 31, 2017
$
(7.2
)
 
$
13.8

 
$
113.3

 
$
119.9

Other comprehensive income
2.2

 
—

 
—

 
2.2

Net loss
—

 
(1.1
)
 
(55.6
)
 
(56.7
)
Amortization of phantom units
—

 
—

 
2.1

 
2.1

Settlement of tax withholdings on equity-based incentive compensation
—

 
—

 
(0.9
)
 
(0.9
)
Balance at June 30, 2018
$
(5.0
)
 
$
12.7

 
$
58.9

 
$
66.6

See accompanying notes to unaudited condensed consolidated financial statements.

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Table of Contents

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
 
Six Months Ended June 30,
 
2018

2017
 
(In millions)
Operating activities
 
 
 
Net income (loss)
$
(56.7
)

$
3.4

Adjustments to reconcile net income (loss) to net cash used in operating activities:
 
 
 
Net loss from discontinued operations
2.6

 
10.1

Depreciation and amortization
59.2


74.2

Amortization of turnaround costs
6.0


14.0

Non-cash interest expense
4.4


4.8

Loss on debt extinguishment costs
58.8

 
—

Unrealized gain on derivative instruments
(2.8
)

(11.9
)
Asset impairment
—

 
0.4

Equity based compensation
3.0


3.3

Lower of cost or market inventory adjustment
(15.0
)
 
(9.2
)
Other non-cash activities
0.2


5.0

Changes in assets and liabilities:
 
 
 
Accounts receivable
19.5


(25.9
)
Inventories
(2.6
)

(38.3
)
Prepaid expenses and other current assets
2.2


(2.1
)
Derivative activity
(0.3
)

(0.3
)
Turnaround costs
(7.6
)

(10.3
)
Accounts payable
(17.7
)

8.1

Accrued interest payable
(20.3
)

(0.1
)
Accrued salaries, wages and benefits
(6.7
)

10.2

Other taxes payable
5.2


0.5

Other liabilities
(54.7
)

(55.6
)
Pension and postretirement benefit obligations
—


(0.4
)
Net cash used in discontinued operations
—

 
(15.5
)
Net cash used in operating activities
(23.3
)
 
(35.6
)
Investing activities
 
 
 
Additions to property, plant and equipment
(33.3
)

(29.7
)
Investment in unconsolidated affiliate
(3.8
)

—

Proceeds from sale of unconsolidated affiliate
9.9

 
—

Proceeds from sale of business, net
28.4

 
—

Proceeds from sale of property, plant and equipment
0.2

 
—

Net cash (used in) provided by discontinued investing activities
3.4

 
(0.3
)
Net cash (used in) provided by investing activities
4.8

 
(30.0
)
Financing activities
 
 
 
Proceeds from borrowings — revolving credit facility
141.0

 
606.9

Repayments of borrowings — revolving credit facility
(141.1
)
 
(616.7
)
Repayments of borrowings — senior notes
(400.0
)
 
—

Payments on capital lease obligations
(1.8
)
 
(4.5
)
Proceeds from (payments on) inventory financing agreements
(4.0
)
 
105.4

Payments on other financing obligations
(1.6
)
 
(1.1
)
Payments on extinguishment of debt
(46.6
)
 
—

Debt issuance costs
(2.9
)
 
(2.1
)
Contributions from Calumet GP, LLC
—

 
0.1

Net cash provided by (used in) financing activities
(457.0
)
 
88.0

Net increase (decrease) in cash, cash equivalents and restricted cash
(475.5
)
 
22.4

Cash, cash equivalents and restricted cash at beginning of period
514.3


4.2

Cash, cash equivalents and restricted cash at end of period
$
38.8

 
$
26.6

Supplemental disclosure of non-cash investing activities
 
 
 
Non-cash property, plant and equipment additions
$
2.5

 
$
6.5

See accompanying notes to unaudited condensed consolidated financial statements.

8
Table of Contents

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 June 30, 2018, the Company had 77,081,069 limited partner common units and 1,573,083 general partner equivalent units outstanding. The general partner owns 2% of the Company and all of the incentive distribution rights (as defined in the Company’s partnership agreement), while the remaining 98% is owned by limited partners. The general partner employs all of the Company’s employees and the Company reimburses the general partner for certain of its expenses.
The Company’s core business is the production and marketing of crude oil-based specialty products including lubricating oils, solvents, waxes, synthetic lubricants and other products. The Company is also engaged in the production and marketing of fuel and fuel related products including gasoline, diesel, jet fuel, asphalt and other products. The Company is based in Indianapolis, Indiana and owns specialty and fuel products facilities. The Company owns and leases additional facilities, primarily related to production and marketing of specialty and fuel products, throughout the United States (“U.S.”). Subsequent to the sale of Anchor Drilling Fluids USA, LLC (“Anchor”) on November 21, 2017, the Company manages its business in two reportable segments: specialty products and fuel products.
On November 8, 2017, the Company completed the sale of all of the issued and outstanding membership interests in Calumet Superior, LLC, which owns the Superior, Wisconsin refinery (“Superior Refinery”). The sale included the associated working capital, the Superior Refinery’s wholesale marketing business and related assets, including certain owned or leased product terminals, and certain crude gathering assets and line space in North Dakota to Husky Superior Refining Holding Corp (the “Superior Transaction”). The Superior Transaction did not qualify for discontinued operations.
Prior to November 21, 2017, the Company owned and operated Anchor, which provided oilfield services and products in the U.S. On November 21, 2017, the Company completed the sale of Anchor; therefore, effective in its fourth quarter of 2017, the Company classified its results of operations and the assets and liabilities, 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. See Note 5 - “Discontinued Operations” for further discussion.
The unaudited condensed consolidated financial statements of the Company as of June 30, 2018 and for the three and six months ended June 30, 2018 and 2017, 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 six months ended June 30, 2018 are not necessarily indicative of the results that may be expected for the year ending December 31, 2018. These unaudited condensed consolidated financial statements should be read in conjunction with the Company’s 2017 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):
 
June 30, 2018
 
December 31, 2017
RINs Obligation
$
5.8

 
$
59.1

Other
16.5

 
14.6

Total
$
22.3

 
$
73.7


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The Company’s Renewable Identification Numbers (“RINs”) obligation (“RINs Obligation”) represents a liability for the purchase of RINs to satisfy the EPA requirement to blend biofuels into the fuel products it produces pursuant to the EPA’s RFS. RINs are assigned to biofuels produced in the U.S. as required by the EPA. The EPA sets annual quotas for the percentage of biofuels that must be blended into transportation fuels consumed in the U.S. and, as a producer of motor fuels from petroleum, the Company is required to blend biofuels into the fuel products it produces at a rate that will meet the EPA’s annual quota. To the extent the Company is unable to blend biofuels at that rate, it must purchase RINs in the open market to satisfy the annual requirement. The Company’s RINs Obligation is based on the amount of RINs it must purchase and the price of those RINs as of the balance sheet date.
The Company uses the inventory model to account for RINs, measuring acquired RINs at weighted-average cost. The cost of RINs used each period is charged to cost of sales with cash inflows and outflows recorded in the operating cash flow section of the unaudited condensed consolidated statements of cash flows. The liability is calculated by multiplying the RINs shortage (based on actual results) by the period end RIN spot price. The Company recognizes an asset at the end of each reporting period in which it has generated RINs in excess of its RINs Obligation. The asset is initially recorded at cost at the time the Company acquires them and are subsequently revalued at the lower of cost or market as of the last day of each accounting period and the resulting adjustments are reflected in costs of sales for the period in the 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 assets and 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.
Restricted Cash
The sale of the Superior Refinery resulted in restricted cash and was based upon the value of collateral under the Company’s debt agreements. Under the indentures governing the Company’s senior notes, proceeds from Asset Sales (as defined in the indentures) can only be used for, among other things, to repay, redeem or repurchase debt; to make certain acquisitions or investments; and to make capital expenditures. On April 9, 2018, the Company redeemed all of the 2021 Secured Notes (defined below) using the restricted cash from the sale of the Superior Refinery.
New Accounting Pronouncements
In June 2018, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2018-07, Improvements to Nonemployee Share-Based Payment Accounting (Topic 718) (“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 shared-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 will not have an impact on the Company’s consolidated financial statements.
In February 2016, FASB issued ASU No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which supersedes the lease accounting requirements in Accounting Standards Codification (“ASC”) Topic 840, Leases. ASU 2016-02 provides principles for the recognition, measurement, presentation and disclosure of leases for both lessees and lessors. The new standard requires lessees to apply a dual approach, classifying leases as either finance or operating leases based on the principle of whether or not the lease is effectively a financed purchase by the lessee. This classification will determine whether lease expense is recognized based on an effective interest method or on a straight-line basis over the term of the lease, respectively. A lessee is also required to record a right-of-use asset and a lease liability for all leases with a term of greater than twelve months regardless of classification. Leases with a term of twelve months or less will be accounted for similar to existing guidance for operating leases. In December 2017 and January 2018, the FASB released ASU 2017-13 and ASU 2018-01, respectively, which contain modifications to ASU 2016-02. The amendments in these standards are effective for fiscal years (including interim periods) beginning after December 15, 2018, with early adoption permitted and modified retrospective application required.
As a result of adoption of ASU 2016-02, the Company anticipates it will recognize a right of use asset and lease liability on the adoption date. The Company plans to apply practical expedients provided in the standard that allow, amongst others, not to reassess contracts that commenced prior to the adoption. The Company also anticipates to elect a policy not to recognize right of use assets and lease liabilities related to short-term leases. The Company continues to evaluate its contracts and is gathering the necessary data to determine the financial impact of ASU 2016-02 on its consolidated financial statements and related disclosures. The Company is also evaluating its systems, processes, internal controls and technology requirements and solutions needed to comply with the requirements of this standard. While the Company cannot currently estimate the financial impact of ASU 2016-02 on its consolidated financial statements, the adoption is anticipated to result in an increase in both assets and liabilities related to its leases.

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In January 2016, the FASB issued ASU No. 2016-01, Financial Instruments — Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities (“ASU 2016-01”). ASU 2016-01 requires that (i) equity investments in unconsolidated entities that are not accounted for under the equity method of accounting generally be measured at fair value with changes recognized in net income (loss) and (ii) when the fair value option has been elected for financial liabilities, changes in fair value due to instrument-specific credit risk be recognized separately in other comprehensive income (loss). Additionally, ASU 2016-01 changes the presentation and disclosure requirements for financial instruments. In February 2018, the FASB issued ASU No. 2018-03, Technical Corrections and Improvements to Financial Instruments—Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities (“ASU 2018-03”). ASU 2018-03 clarifies certain aspects of the guidance issued in ASU 2016-01. The adoption of ASU 2016-01 did not have an impact on the Company’s consolidated financial statements.
On January 1, 2018, the Company adopted ASU No. 2014-09, Revenue - Revenue from Contracts with Customers (Topic 606) (“ASC 606”) and all the related amendments to all contracts using the modified retrospective method. The comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods. The adoption of ASC 606 did not have a material impact to our revenue recognition. See Note 3 - “Revenue Recognition” for further information.
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, solvents, waxes, synthetic lubricants 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.
Excise and Sales Taxes
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 that occur before the customer obtains control of the goods are deemed to be fulfillment activities and are included in transportation expense. The Company has elected to account for shipping and handling activities that occur after the customer has obtained control of a good as 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.

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Disaggregation of Revenue
The following table reflects the disaggregation of revenue by major source (in millions):
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2018
 
2017
 
2018
 
2017
Sales by major source
 
 
 
 
 
 
 
Standard specialty products
$
309.7

 
$
269.9

 
$
563.5

 
$
537.8

Packaged and synthetic specialty products
72.9

 
73.2

 
140.9

 
142.5

Total specialty products
$
382.6

 
$
343.1

 
$
704.4

 
$
680.3

 
 
 
 
 
 
 
 
Fuel and fuel related products
$
500.8

 
$
533.5

 
$
896.3

 
$
1,039.6

Asphalt
62.1

 
90.4

 
95.3

 
133.6

Total fuel products
$
562.9

 
$
623.9

 
$
991.6

 
$
1,173.2

 
 
 
 
 
 
 
 
Total sales
$
945.5

 
$
967.0

 
$
1,696.0

 
$
1,853.5

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 June 30, 2018 and December 31, 2017 was $269.9 million and $265.4 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.
There were no material differences under ASC 606 compared to ASC 605 for the three and six months ended June 30, 2018.
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. 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 $0.6 million and $4.6 million lower as of June 30, 2018 and December 31, 2017, 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

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with Macquarie, the Supply and Offtake Agreements are accounted for by the Company similar to a product financing arrangement; therefore, the inventories sold to Macquarie will continue to be included in the Company’s consolidated balance sheets until processed and sold to a third party. The Company is obligated to repurchase the inventory in certain scenarios.
Inventories consist of the following (in millions):
 
June 30, 2018
 
December 31, 2017
 
Titled
Inventory
 
Supply and Offtake
Agreements (1)
 
Total
 
Titled
Inventory
 
Supply and Offtake
Agreements (1)
 
Total
Raw materials
$
47.3

 
$
18.2

 
$
65.5

 
$
42.0

 
$
17.6

 
$
59.6

Work in process
45.4

 
27.7

 
73.1

 
34.4

 
23.7

 
58.1

Finished goods
136.2

 
59.3

 
195.5

 
139.4

 
57.3

 
196.7

 
$
228.9

 
$
105.2

 
$
334.1

 
$
215.8

 
$
98.6

 
$
314.4

 
(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. Such write downs are subject to reversal in subsequent periods, not to exceed LIFO cost, if prices recover. During the three months ended June 30, 2018 and 2017, the Company recorded decreases of $11.9 million and $3.8 million, respectively, in cost of sales in the unaudited condensed consolidated statements of operations due to the lower of cost or market (“LCM”) valuation. During the six months ended June 30, 2018 and 2017, the Company recorded decreases of $15.0 million and $9.2 million, respectively, in cost of sales in the unaudited condensed consolidated statements of operations due to the LCM valuation.
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, for total consideration of approximately $88.4 million (subject to further post-closing adjustments) including a base price of $50.0 million, $13.0 million to be paid at various times over the next two years for net working capital and other items and 10% equity ownership in Fluid Holding Corp. (“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.
As of June 30, 2018 and December 31, 2017, the Company had an $8.2 million and a $15.1 million receivable respectively, in other accounts receivable in the consolidated balance sheet for the remaining payment of the base price and working capital.
As of June 30, 2018 and December 31, 2017, the Company had a $7.1 million receivable in other noncurrent assets, net in the consolidated balance sheet for the remaining payment of working capital.
The following table summarizes the results of discontinued operations for the periods presented (in millions):
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2018
 
2017
 
2018
 
2017
Sales
$
—

 
$
63.9

 
$
—

 
$
114.8

Cost of sales
—

 
(47.2
)
 
—

 
(88.1
)
Selling
—

 
(13.1
)
 
—

 
(24.3
)
Other
(0.7
)
 
(6.9
)
 
(2.6
)
 
(13.4
)
Net loss from discontinued operations before income taxes
$
(0.7
)
 
$
(3.3
)
 
$
(2.6
)
 
$
(11.0
)
Income tax benefit
—

 
0.9

 
—

 
0.9

Net loss from discontinued operations net of income taxes
$
(0.7
)
 
$
(2.4
)
 
$
(2.6
)
 
$
(10.1
)

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6. Investment In Unconsolidated Affiliates
The following table summarizes the Company’s investments in unconsolidated affiliates (in millions):
 
June 30, 2018
 
December 31, 2017
 
Investment
 
Percent Ownership
 
Investment
 
Percent Ownership
Pacific New Investment Limited
$
—

 
—
%
 
$
9.6

 
23.8
%
Fluid Holding Corp.
25.4

 
10.0
%
 
25.4

 
10.0
%
Total
$
25.4

 
 
 
$
35.0

 
 
Pacific New Investment Limited and Shandong Hi-Speed Hainan Development Co., Ltd.
In 2015, the Company and The Heritage Group (“Heritage Group”), a related party, formed Pacific New Investment Limited (“PACNIL”) for the purpose of investing in a joint venture with Shandong Hi-Speed Materials Group Corporation and China Construction Installation Engineering Co., Ltd. to construct, develop and operate a solvents refinery in mainland China. The joint venture is named Shandong Hi-Speed Hainan Development Co., Ltd. (“Hi-Speed”). The Company invested $4.8 million in June 2016 and $4.8 million in October 2016. Through the Company’s ownership of an equity interest in PACNIL, the Company previously owned an equity interest of approximately 6.0% in Hi-Speed. During the three months ended June 30, 2018, PACNIL sold its investment in Hi-Speed to the other owners. The Company received proceeds of $9.9 million for the sale.
Fluid Holding Corp.
In connection with the Anchor Transaction in November 2017, the Company received an 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 without a readily determinable fair value 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.
Biosyn Holdings, LLC and Biosynthetic Technologies
In 2018, the Company and 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. The Company incurred approximately $4.0 million in related expenditures. The Company, through Biosyn, intends to explore a range of alternatives to maximize the value of the acquired intellectual property. This could include internal or external licensing or the sale of the technology for applications across a diverse portfolio of products and solutions in a variety of end-markets. The Company is designing a commercial scale test at its existing esters manufacturing plant in Missouri. The Company accounts 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 matters, claims and litigation incidental to its business, including claims made by various regulatory and taxation authorities, such as the EPA, the SEC, various state environmental regulatory bodies, the Internal Revenue Service, various state and local departments of revenue and the U.S. Occupational Safety and Health Administration (“OSHA”), as the result of audits or reviews of the Company’s business. In addition, the Company has property, business interruption, general liability and various other insurance policies that may result in certain losses or expenditures being reimbursed to the Company.
Environmental
The Company conducts crude oil and specialty hydrocarbon refining, blending and terminal operations and such activities are subject to stringent federal, state, regional and local laws and regulations governing worker health and safety, the discharge of materials into the environment and environmental protection. These laws and regulations impose obligations that are applicable to the Company’s operations, such as requiring the acquisition of permits to conduct regulated activities, restricting the manner in which the Company may release materials into the environment, requiring remedial activities or capital expenditures to mitigate pollution from former or current operations, requiring the application of specific health and safety criteria addressing worker protection and imposing substantial liabilities for pollution resulting from its operations. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil and criminal penalties; the imposition of investigatory, remedial or corrective action obligations or the incurrence of capital expenditures; the occurrence of delays in the permitting, development or expansion of projects and the issuance of injunctive relief limiting or prohibiting Company activities. Moreover, certain of these laws impose joint and several, strict liability for costs required to remediate and restore sites where petroleum hydrocarbons, wastes or other materials have been released or disposed. In addition, new laws and regulations, new interpretations of existing laws and regulations, increased governmental enforcement or other developments, some of which legal requirements are discussed below, could significantly increase the Company’s operational or compliance expenditures.

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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 HollyFrontier Corporation (“Holly”), the owner and operator of the Great Falls refinery prior to its acquisition by Connacher, under an asset purchase agreement between Holly and Connacher, pursuant to which Connacher acquired the Great Falls refinery. Under this asset purchase agreement, Holly agreed to indemnify Connacher and Montana Refining Company, Inc., subject to timely notification, certain conditions and certain monetary baskets and caps, for environmental conditions arising under Holly’s ownership and operation of the Great Falls refinery and existing as of the date of sale to Connacher. During 2014, Holly provided the Company a notice challenging the Company’s position that Holly is obligated to indemnify the Company’s remediation expenses for environmental conditions to the extent arising under Holly’s ownership and operation of the refinery and existing as of the date of sale to Connacher, which expenditures totaled approximately $17.0 million as of June 30, 2018, of which $14.6 million was capitalized into the cost of the Company’s recently completed refinery expansion project and $2.4 million was expensed. The Company continues to believe that Holly is responsible to indemnify the Company for these remediation expenses disputed by Holly and on September 22, 2015, the Company initiated a lawsuit against Holly and the sellers of the Great Falls refinery under the asset purchase agreement. On November 24, 2015, Holly and the sellers of the Great Falls refinery under the asset purchase agreement filed a motion to dismiss the case pending arbitration. On February 10, 2016, the court ordered that all of the claims be addressed in arbitration. The arbitration panel conducted the first phase of the arbitration in July 2018.  The Company expects that the arbitration panel will render its decision with respect to the issues addressed in the first phase of the arbitration this Fall. The second phase of the arbitration regarding damages is scheduled to occur in early 2019. In the event the Company is unsuccessful in the legal dispute with Holly, the Company will be responsible for the remediation expenses. The Company expects that it may incur costs to remediate other environmental conditions at the Great Falls refinery; however, the costs cannot be estimated at this time. The Company believes at this time that these other costs it may incur will not be material to its financial position or results of operations.
Renewable Identification Numbers Obligation
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 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 2017, compliance with the RFS would represent a “disproportionate economic hardship” for these small refineries.
In February 2017 and in May 2017, the EPA granted the Company’s fuel products refineries a “small refinery exemption” under the RFS for the compliance year 2016, 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 2016, 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 with the exception of the June 30, 2018 portion related to the Superior Refinery which is charged to other (income) expense within operating income in the unaudited condensed consolidated statement of operations. As of June 30, 2018 and December 31, 2017, the Company had a RINs Obligation of $5.8 million and $59.1 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 and comparable state laws. These laws and regulations strictly govern the protection of the health and safety of employees. In addition, OSHA’s hazard communication standard requires that information be maintained about hazardous materials used or produced in the Company’s operations and that this information be provided to employees, contractors, state and local government authorities and customers. The Company maintains safety and training programs as part of its ongoing efforts to promote compliance with applicable laws and regulations. The Company conducts periodic audits of Process Safety Management (“PSM”) systems at each of its locations subject to the PSM standard. The Company’s compliance with applicable health and safety laws and regulations has required and continues to require, substantial expenditures. Changes in occupational safety and health laws and regulations or a finding of non-compliance with current laws and regulations could

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result in additional capital expenditures or operating expenses, as well as civil penalties and, in the event of a serious injury or fatality, criminal charges.
In the first quarter of 2011, OSHA conducted an inspection of the Cotton Valley refinery’s PSM program. On March 14, 2011, OSHA issued a Citation and Notification of Penalty (the “Cotton Valley Citation”) to the Company as a result of the Cotton Valley inspection, which included a proposed penalty amount of $0.2 million. The Company has contested the Cotton Valley Citation and the parties have reached a tentative settlement with OSHA on the matter, which the Company does not believe will have a material adverse effect on its financial position or results of operations.
Other Matters, Claims and Legal Proceedings
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 same voluntary production requests by the SEC as well as additional, related documents. The Company has, from the outset, cooperated with the SEC’s requests and intends to continue to do so. Currently, the Company cannot estimate the timing, or ultimate outcome, including financial impact, if any, resulting from the SEC’s investigation.

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.
Standby Letters of Credit
The Company has agreements with various financial institutions for standby letters of credit, which have been issued primarily to vendors. As of June 30, 2018 and December 31, 2017, the Company had outstanding standby letters of credit of $30.8 million and $67.3 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 June 30, 2018 and December 31, 2017, 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 and $600.0 million, respectively, which amount may be increased with the consent of the Agent (as defined in the revolving credit facility agreement) to 90% of revolver commitments then in effect ($600.0 million and $900.0 million at June 30, 2018 and December 31, 2017, respectively).
8. Inventory Financing Agreements
On March 31, 2017, the Company entered into several agreements with Macquarie to support the operations of the Great Falls refinery (the “Great Falls Supply and Offtake Agreements”). The Great Falls Supply and Offtake Agreements expire on September 30, 2019. On July 27, 2017, the Company amended the Great Falls Supply and Offtake Agreements to provide Macquarie the option to terminate the Great Falls Supply and Offtake Agreements with nine months’ notice any time prior to June 2019 and the Company the option to terminate with ninety days’ notice at any time.
On June 19, 2017, the Company entered into several agreements with Macquarie to support the operations of the Shreveport refinery (the “Shreveport Supply and Offtake Agreements” and together with the Great Falls Supply and Offtake Agreements, the “Supply and Offtake Agreements”). The Shreveport Supply and Offtake Agreements expire on June 30, 2020; however, Macquarie has the option to terminate the Shreveport Supply and Offtake Agreements with nine months’ notice any time prior to June 2019 and the Company has the option to terminate with ninety days’ notice at any time.
During the terms of the Supply and Offtake Agreements, the Company may purchase crude oil from Macquarie or one of its affiliates. Per the Supply and Offtake Agreements, Macquarie will provide up to 30,000 barrels per day of crude oil to the Great Falls refinery and 60,000 barrels per day of crude oil to the Shreveport refinery. The Company agreed to purchase the crude oil on a just-in-time basis to support the production operations at the Great Falls and Shreveport refineries. Additionally, the Company agreed to sell, and Macquarie agreed to buy, at market prices, refined products produced at the Great Falls and Shreveport refineries. For Shreveport, finished products consisting of finished fuel products (other than jet fuel), lubricants and waxes, Macquarie may (but is not required to) sell such products to the sales intermediation party (“SIP”), and the SIP may (but is not required to) sell such products to Shreveport, as applicable, for sale in turn to third parties. For jet fuel and certain intermediate products, Macquarie

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may (but is not required to) sell such products to Shreveport for sale thereby to third parties. The Company will then repurchase the refined products from Macquarie or the SIP prior to selling the refined products to third parties.
The Supply and Offtake Agreements are subject to minimum and maximum inventory levels. The agreements also provide for the lease to Macquarie of crude oil and certain refined product storage tanks located at the Great Falls and Shreveport refineries and certain offsite locations. Following expiration or termination of the agreements, Macquarie has the option to require the Company to purchase the crude oil and refined product inventories then owned by Macquarie and located at the leased storage tanks at then current market prices. In addition, barrels owned by the Company are pledged as collateral to support the Deferred Payment Arrangement (defined below) obligations under these agreements.
While title to certain inventories will reside with Macquarie, the Supply and Offtake Agreements are accounted for by the Company similar to a product financing arrangement; therefore, the inventories sold to Macquarie will continue to be included in the Company’s condensed consolidated balance sheets until processed and sold to a third party. Each reporting period, the Company will record liabilities in an amount equal to the amount the Company expects to pay to repurchase the inventory held by Macquarie based on market prices at the termination date included in obligations under inventory financing agreements in the condensed consolidated balance sheets. The Company has determined that the redemption feature on the initially recognized liabilities related to the Supply and Offtake Agreements 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 derivative activity in the financing activities section in the unaudited condensed consolidated statements of cash flows.
For the three and six months ended June 30, 2018, the Company incurred $5.4 million and $7.1 million, respectively, for financing costs related to the Supply and Offtake Agreements and is included in interest expense in the Company’s unaudited condensed consolidated statements of operations. The Company incurred $0.4 million of financing costs for the three and six months ended June 30, 2017.
The Company has provided collateral of $6.8 million related to the initial purchase of the Great Falls and Shreveport inventory to cover credit risk for future crude oil deliveries and potential liquidation risk if Macquarie exercises its rights and sells the inventory to third parties. The collateral was recorded as a reduction to the obligations under inventory financing agreements pursuant to a master netting agreement.
The Supply and Offtake Agreements also include a deferred payment arrangement (“Deferred Payment Arrangement”) whereby the Company can defer payments on just-in-time crude oil purchases from Macquarie owed under the agreements up to the value of the collateral provided (90% of the collateral inventory). The deferred amounts under the Deferred Payment Arrangement will bear interest at a rate equal to LIBOR plus 3.25% per annum for both Shreveport and Great Falls. Amounts outstanding under the Deferred Payment Arrangement are included in obligations under inventory financing agreements in the Company’s 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 June 30, 2018 and December 31, 2017, the capacity of the Deferred Payment Arrangement was $10.9 million and $17.8 million, respectively, and the Company had $11.4 million and $11.3 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 June 30, 2018.

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9. Long-Term Debt
Long-term debt consisted of the following (in millions):
 
June 30, 2018
 
December 31, 2017
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 6.2% and 8.4% for the six months ended June 30, 2018 and year ended December 31, 2017, respectively.
$
0.1

 
$
0.2

Borrowings under 2021 Secured Notes, interest at a fixed rate of 11.5%, interest payments semiannually, borrowings due January 2021, effective interest rate of 12.3% for the six months ended June 30, 2018 and the year ended December 31, 2017.
—

 
400.0

Borrowings under 2021 Notes, interest at a fixed rate of 6.5%, interest payments semiannually, borrowings due April 2021, effective interest rate of 6.8% for each the six months ended June 30, 2018 and the year ended December 31, 2017.
900.0


900.0

Borrowings under 2022 Notes, interest at a fixed rate of 7.625%, interest payments semiannually, borrowings due January 2022, effective interest rate of 8.0% for each the six months ended June 30, 2018 and the year ended December 31, 2017. (1)
351.8

 
352.1

Borrowings under 2023 Notes, interest at a fixed rate of 7.75%, interest payments semiannually, borrowings due April 2023, effective interest rate of 8.0% for each the six months ended June 30, 2018 and the year ended December 31, 2017.
325.0

 
325.0

Other
5.9

 
6.6

Capital lease obligations, at various interest rates, interest and principal payments monthly through November 2034.
42.2

 
44.0

Less unamortized debt issuance costs (2)
(18.2
)
 
(25.9
)
Less unamortized discounts
(4.3
)
 
(9.7
)
Total long-term debt
$
1,602.5

 
$
1,992.3

Less current portion of long-term debt
2.9

 
354.1

 
$
1,599.6

 
$
1,638.2

 
(1) 
The balance includes a fair value interest rate hedge adjustment, which increased the debt balance by $1.8 million and $2.1 million as of June 30, 2018 and December 31, 2017, respectively.
(2) 
Deferred debt issuance costs are being amortized by the effective interest rate method over the lives of the related debt instruments. These amounts are net of accumulated amortization of $21.1 million and $21.8 million at June 30, 2018 and December 31, 2017, respectively.
Senior Notes
11.50% Senior Secured Notes (the “2021 Secured Notes”)
On April 20, 2016, the Company issued and sold $400.0 million in aggregate principal amount of 11.50% Senior Secured Notes due January 15, 2021, in a private placement pursuant to Section 4(a)(2) of the Securities Act of 1933, as amended (the “Securities Act”), to eligible purchasers at a discounted price of 98.273 percent of par. Subject to certain exceptions, the 2021 Secured Notes were secured by a lien on all of the fixed assets that secure the Company’s obligations under its secured hedge agreements, including certain present and future real property, fixtures and equipment; all U.S. registered patents and patent license rights, trademarks and trademark license rights, copyrights and copyright license rights and trade secrets; chattel paper, documents and instruments; certain cash deposits in the property, plant and equipment proceeds account; certain books and records; and all accessions and proceeds of any of the foregoing. Interest on the 2021 Secured Notes was paid semiannually in arrears on January 15 and July 15 of each year, beginning on July 15, 2016. In April 2018, the Company redeemed all of the 2021 Secured Notes. In conjunction with the redemption, the Company incurred debt extinguishment costs of $58.2 million, including $11.6 million of non-cash charges.

18
Table of Contents

2021 Notes, 2022 Notes and 2023 Notes
In accordance with SEC Rule 3-10 of Regulation S-X, unaudited condensed consolidated financial statements of non-guarantors are not required. The Company has no assets or operations independent of its subsidiaries. Obligations under its 2021, 2022 and 2023 Notes are fully and unconditionally and jointly and severally guaranteed on a senior unsecured basis by the Company’s current 100%-owned operating subsidiaries and certain of the Company’s future operating subsidiaries, with the exception of the Company’s “minor” subsidiaries (as defined by Rule 3-10 of Regulation S-X), including Calumet Finance Corp. (100%-owned Delaware corporation that was organized for the sole purpose of being a co-issuer of certain of the Company’s indebtedness, including the 2021, 2022 and 2023 Notes). There are no significant restrictions on the ability of the Company or subsidiary guarantors for the Company to obtain funds from its subsidiary guarantors by dividend or loan. None of the subsidiary guarantors’ assets represent restricted assets pursuant to SEC Rule 4-08(e)(3) of Regulation S-X.
The 2021, 2022 and 2023 Notes are subject to certain automatic customary releases, including the sale, disposition or transfer of capital stock or substantially all of the assets of a subsidiary guarantor, designation of a subsidiary guarantor as unrestricted in accordance with the applicable indenture, exercise of legal defeasance option or covenant defeasance option, liquidation or dissolution of the subsidiary guarantor and a subsidiary guarantor ceases to both guarantee other Company debt and to be an obligor under the revolving credit facility. The Company’s operating subsidiaries may not sell or otherwise dispose of all or substantially all of their properties or assets to, or consolidate with or merge into, another company if such a sale would cause a default under the indentures governing the 2021, 2022 and 2023 Notes.
The indentures governing the 2021, 2022 and 2023 Notes contain covenants that, among other things, restrict the Company’s ability and the ability of certain of the Company’s subsidiaries to: (i) sell assets; (ii) pay distributions on, redeem or repurchase the Company’s common units or redeem or repurchase its subordinated debt; (iii) make investments; (iv) incur or guarantee additional indebtedness or issue preferred units; (v) create or incur certain liens; (vi) enter into agreements that restrict distributions or other payments from the Company’s restricted subsidiaries to the Company; (vii) consolidate, merge or transfer all or substantially all of the Company’s assets; (viii) engage in transactions with affiliates and (ix) create unrestricted subsidiaries. These covenants are subject to important exceptions and qualifications. At any time when the 2021, 2022 and 2023 Notes are rated investment grade by either Moody’s Investors Service, Inc. (“Moody’s”) or S&P Global Ratings (“S&P”) and no Default or Event of Default, each as defined in the indentures governing the 2021, 2022 and 2023 Notes, has occurred and is continuing, many of these covenants will be suspended. As of June 30, 2018, the Company’s Fixed Charge Coverage Ratio (as defined in the indentures governing the 2021, 2022 and 2023 Notes) was 1.6 to 1.0. As of June 30, 2018, 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 a third amended and restated senior secured revolving credit facility 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 2021. The reductions in FILO commitments covert 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. 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 a basis points margin or LIBOR plus a basis points 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%
As of June 30, 2018, the margin was 50 basis points for prime rate based revolver loans, 150 basis points for LIBOR based revolver loans, 150 basis points for prime rate based FILO loans and 250 basis points for LIBOR based FILO loans. In addition, if the Leverage Ratio (as defined in the revolving credit facility agreement) is less than 5.5 to 1.0 for any four fiscal quarter period ending on or after August 23, 2018, then, after such fiscal quarter, the margins otherwise applicable will be reduced by 25 basis points. 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.

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In addition to paying interest quarterly on outstanding borrowings under the revolving credit facility, the Company is required to pay a commitment fee to the lenders under the revolving credit facility with respect to the unutilized commitments thereunder at a rate equal to 0.250% or 0.375% per annum depending on the average daily available unused borrowing capacity for the preceding month. The Company also pays a customary letter of credit fee, including a fronting fee of 0.125% per annum of the stated amount of each outstanding letter of credit, and customary agency fees.
In addition, 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: 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 Borrowing Base (as defined in the revolving credit facility agreement) and (ii) $35 million (which amount is subject to increase in proportion to revolving commitment increases), the Company will be required to maintain as of the end of each fiscal quarter a Fixed Charge Coverage Ratio (as defined in the revolving credit facility agreement) of at least 1.0 to 1.0. As of June 30, 2018, the Company was in compliance with all covenants under the revolving credit facility.
Capital Lease
The Company is a party to a Throughput and Deficiency Agreement with TexStar Midstream Logistics, L.P. (“TexStar”) under which TexStar owns and operates a crude oil pipeline system delivering crude oil to the Company’s San Antonio refinery (the “Pipeline Agreement”). The Pipeline Agreement has an initial term of 20 years (through August 2034) and is accounted for as a capital lease on the Company’s consolidated balance sheets. TexStar and the Company have each terminated the Pipeline Agreement for alleged breaches of the Pipeline Agreement. The parties are currently operating under the Pipeline Agreement as TexStar and the Company are discussing potential alternatives to the Pipeline Agreement. However, there can be no guarantee that the Company will reach a new agreement or that, if an agreement is reached, that it will include more favorable terms. In the event the parties do not enter into a new agreement and their dispute relating to the Pipeline Agreement is litigated, the Company believes it will be successful, in which case the Company will be relieved of future payment obligations under the Pipeline Agreement.  In the event the Company is not successful in the dispute, the Company may be obligated to continue making certain, minimum payments over the remaining term of the Pipeline Agreement. As of June 30, 2018, the total capital lease obligation under the Pipeline Agreement recorded on the Company’s consolidated balance sheets was $38.1 million.
Maturities of Long-Term Debt
As of June 30, 2018, principal payments on debt obligations and future minimum rentals on capital lease obligations are as follows (in millions):
Year
Maturity
2018
$
1.5

2019
2.8

2020
2.4

2021
903.3

2022
351.2

Thereafter
362.0

Total
$
1,623.2

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 (“LLS”), Western Canadian Select (“WCS”), WTI Midland, Mixed Sweet Blend (“MSW”) and ICE Brent (“Brent”).

20
Table of Contents

The Company manages its exposure to commodity markets, credit, volumetric and liquidity risks to manage its costs and volatility of cash flows as conditions warrant or opportunities become available. These risks may be managed in a variety of ways that may include the use of derivative instruments. Derivative instruments may be used for the purpose of mitigating risks associated with an asset, liability and anticipated future transactions and the changes in fair value of the Company’s derivative instruments will affect its earnings and cash flows; however, such changes should be offset by price or rate changes related to the underlying commodity or financial transaction that is part of the risk management strategy. The Company does not speculate with derivative instruments or other contractual arrangements that are not associated with its business objectives. Speculation is defined as increasing the Company’s natural position above the maximum position of its physical assets or trading in commodities, currencies or other risk bearing assets that are not associated with the Company’s business activities and objectives. The Company’s positions are monitored routinely by a risk management committee to ensure compliance with its stated risk management policy and documented risk management strategies. All strategies are reviewed on an ongoing basis by the Company’s risk management committee, which will add, remove or revise strategies in anticipation of changes in market conditions and/or its risk profiles. Such changes in strategies are to position the Company in relation to its risk exposures in an attempt to capture market opportunities as they arise. 
The Company is obligated to repurchase crude oil and refined products from Macquarie at the termination of the Supply and Offtake Agreements in certain scenarios. The Company has determined that the redemption feature on the initially recognized liability related to the Supply and Offtake Agreements is an embedded derivative indexed to commodity prices. As such, the Company has accounted for this embedded derivative at fair value with changes in the fair value, if any, recorded in gain (loss) on derivative instruments in the Company’s unaudited condensed consolidated statement 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.
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):
 
 
 
 
June 30, 2018
 
December 31, 2017
 
 
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:
 
 
 
 
 
 
 
 
 
 
Fuel products segment:
 
 
 
 
 
 
 


 
 
 
 
 
 
Crude oil swaps
 
Derivative assets
 
$
—

 
$
—

 
$
—

 
$
0.3

 
$
(0.3
)
 
$
—

WCS crude oil basis swaps
 
Derivative assets
 
0.8

 
(0.2
)
 
0.6

 
—

 
—

 
—

WCS crude oil percentage basis swaps
 
Derivative assets
 
0.6

 
(1.1
)
 
(0.5
)
 
—

 
—

 
—

Midland crude oil basis swaps
 
Derivative assets
 
3.7

 
(1.6
)
 
2.1

 
—

 
—

 
—

Diesel crack spread swap
 
Derivative assets
 
1.9

 
(0.1
)
 
1.8

 
—

 
—

 
—

Diesel percentage basis crack spread swap
 
Derivative assets
 
1.1

 
(1.3
)
 
(0.2
)
 
—

 
—

 
—

Total derivative instruments
 
 
 
$
8.1


$
(4.3
)

$
3.8


$
0.3


$
(0.3
)

$
—


21
Table of Contents

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):
 
 
 
 
June 30, 2018
 
December 31, 2017
 
 
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
 
$
(11.3
)
 
$
—

 
$
(11.3
)
 
$
(4.4
)
 
$
—

 
$
(4.4
)
Crude oil swaps
 
Derivative liabilities
 
—

 
—

 
—

 
—

 
0.3

 
0.3

WCS crude oil basis swaps
 
Derivative liabilities
 
(0.2
)
 
0.2

 
—

 
—

 
—

 
—

WCS crude oil percentage basis swaps
 
Derivative liabilities
 
(1.4
)
 
1.1

 
(0.3
)
 
—

 
—

 
—

Midland crude oil basis swaps
 
Derivative liabilities
 
(0.8
)
 
1.6

 
0.8

 
—

 
—

 
—

Gasoline swaps
 
Derivative liabilities
 
—

 
—

 
—

 
(0.2
)
 
—

 
(0.2
)
Gasoline crack spread swaps
 
Derivative liabilities
 
—

 
—

 
—

 
(1.8
)
 
—

 
(1.8
)
Diesel swaps
 
Derivative liabilities
 
—

 
—

 
—

 
(0.2
)
 
—

 
(0.2
)
Diesel crack spread swaps
 
Derivative liabilities
 
(0.1
)
 
0.1

 
—

 
(4.1
)
 
—

 
(4.1
)
Diesel percentage basis crack spread swaps
 
Derivative liabilities
 
(1.9
)
 
1.3

 
(0.6
)
 
—

 
—

 
—

Total derivative instruments
 
 
$
(15.7
)
 
$
4.3

 
$
(11.4
)
 
$
(10.7
)
 
$
0.3

 
$
(10.4
)
The Company is exposed to credit risk in the event of nonperformance by its counterparties on these derivative transactions. The Company does not expect nonperformance on any derivative instruments, however, no assurances can be provided. The Company’s credit exposure related to these derivative instruments is represented by the fair value of contracts reported as derivative assets. As of June 30, 2018, the Company had four counterparties in which the derivatives held were in net assets totaling $3.8 million. As of December 31, 2017, the Company had no counterparties in which the derivatives held were net assets. To manage credit risk, the Company selects and periodically reviews counterparties based on credit ratings. The Company primarily executes its derivative instruments with large financial institutions that have ratings of at least 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 June 30, 2018 or December 31, 2017. Collateral received from counterparties is reported in other current liabilities, and collateral held by counterparties is reported in prepaid expenses and other current assets on the Company’s condensed consolidated balance sheets and is not netted against derivative assets or liabilities. Any outstanding collateral is released to the Company upon settlement of the related derivative instrument liability. As of June 30, 2018 and December 31, 2017, the Company had provided no collateral to its counterparties.
Certain of the Company’s outstanding derivative instruments are subject to credit support agreements with the applicable counterparties which contain provisions setting certain credit thresholds above which the Company may be required to post agreed-upon collateral, such as cash or letters of credit, with the counterparty to the extent that the Company’s mark-to-market net liability, if any, on all outstanding derivatives exceeds the credit threshold amount per such credit support agreement. The majority of the credit support agreements covering the Company’s outstanding derivative instruments also contain a general provision stating that if the Company experiences a material adverse change in its business, in the reasonable discretion of the counterparty, the Company’s credit

22
Table of Contents

threshold could be lowered by such counterparty. The Company does not expect that it will experience a material adverse change in its business.
The cash flow impact of the Company’s derivative activities is classified primarily as a change in derivative activity in the operating activities section in the unaudited condensed consolidated statements of cash flows.
Derivative Instruments 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 crude oil basis swaps that do not qualify as cash flow hedges for accounting purposes as they were not entered into simultaneously with a corresponding NYMEX WTI derivative contract. Additionally, the Company has entered into gasoline swaps, diesel swaps and certain other crude oil swaps that do not qualify as cash flow hedges for accounting purposes. However, these instruments provide economic hedges of the Company’s crude oil and natural gas purchases and gasoline and diesel sales.
The Company recorded the following gains (losses) in its 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 on Derivative Instruments
 
Amount of Unrealized Gain (Loss) Recognized in Gain on Derivative Instruments
Three Months Ended June 30,
 
Three Months Ended June 30,
2018
 
2017
 
2018
 
2017
Specialty products segment:
 
 
 
 
 
 
 
Natural gas swaps
$
—

 
$
(0.9
)
 
$
—

 
$
0.2

Fuel products segment:
 
 
 
 
 
 
 
Inventory financing obligation
—

 
—

 
(2.9
)
 
(0.9
)
Crude oil swaps
—

 
(1.1
)
 
—

 
(1.5
)
WCS crude oil basis swaps
—

 
1.4

 
0.6

 
3.2

WCS crude oil percentage basis swaps
—

 
0.6

 
(1.1
)
 
0.3

Midland crude oil basis swaps
—

 
—

 
2.9

 
—

Diesel crack spread swaps
—

 
—

 
1.7

 
—

Diesel percentage basis crack spread swaps
—

 
—

 
(0.4
)
 
—

Total
$
—

 
$
—

 
$
0.8

 
$
1.3


23
Table of Contents

The Company recorded the following gains (losses) in its unaudited condensed consolidated statements of operations for the six months ended June 30, 2018 and 2017, related to its derivative instruments not designated as hedges (in millions):
Type of Derivative
Amount of Realized Gain (Loss) Recognized in Gain on Derivative Instruments
 
Amount of Unrealized Gain (Loss) Recognized in Gain on Derivative Instruments
Six Months Ended June 30,
 
Six Months Ended June 30,
2018
 
2017
 
2018
 
2017
Specialty products segment:
 
 
 
 
 
 
 
Natural gas swaps
$
—

 
$
(1.7
)
 
$
—

 
$
(0.6
)
Fuel products segment:
 
 
 
 
 
 
 
Inventory financing obligation
—

 
—

 
(6.9
)
 
(0.9
)
Crude oil swaps
—

 
(1.5
)
 
(0.3
)
 
(4.8
)
WCS crude oil basis swaps
—

 
0.6

 
0.6

 
9.4

WCS crude oil percentage basis swaps
—

 
0.6

 
(0.8
)
 
1.3

Midland crude oil basis swaps
—

 
—

 
2.9

 
—

Gasoline swaps
—

 
—

 
0.2

 
—

Gasoline crack spread swaps
(1.0
)
 
(1.6
)
 
1.8

 
4.8

2/1/1 crack spread swaps
—

 
(1.0
)
 
—

 
—

Diesel swaps
—

 
—

 
0.2

 
—

Diesel crack spread swaps
(1.1
)
 
(0.3
)
 
5.9

 
2.7

Diesel percentage basis crack spread swaps
—

 
—

 
(0.8
)
 
—

Total
$
(2.1
)
 
$
(4.9
)
 
$
2.8

 
$
11.9


Derivative Positions — Fuel Products Segment
Crude Oil Swap Contracts
At December 31, 2017, the Company had the following derivatives related to crude oil purchases in its fuel products segment, none of which are designated as hedges:
Crude Oil Swap Contracts by Expiration Dates
Barrels Purchased
 
BPD
 
Average Swap
($/Bbl)
First Quarter 2018
28,000

 
311

 
$
48.25

Total
28,000

 
 
 
 
Average price
 
 
 
 
$
48.25

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 June 30, 2018, the Company had the following derivatives related to crude oil basis swaps 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 Swap
($/Bbl)
Third Quarter 2018
184,000

 
2,000

 
$
24.98

Fourth Quarter 2018
184,184

 
2,002

 
$
26.13

First Quarter 2019
90,000

 
1,000

 
$
22.20

Second Quarter 2019
91,000

 
1,000

 
$
22.20

Third Quarter 2019
92,000

 
1,000

 
$
22.20

Fourth Quarter 2019
92,000

 
1,000

 
$
22.20

Total
733,184

 
 
 
 
Average price


 


 
$
23.32


24
Table of Contents

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 June 30, 2018, the Company had the following derivatives related to crude oil percentage basis swaps in its fuel products segment, none of which are designated as hedges:
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

 
66.68
%
Second Quarter 2019
455,000

 
5,000

 
66.68
%
Third Quarter 2019
460,000

 
5,000

 
66.68
%
Fourth Quarter 2019
460,000

 
5,000

 
66.68
%
Total
1,825,000

 
 
 
 
Average percentage
 
 
 
 
66.68
%
Midland 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 WTI Midland and NYMEX WTI. At June 30, 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 Swap
($/Bbl)
Third Quarter 2018
782,000

 
8,500

 
$
11.39

Fourth Quarter 2018
874,000

 
9,500

 
$
15.13

First Quarter 2019
765,000

 
8,500

 
$
13.01

Second Quarter 2019
773,500

 
8,500

 
$
11.88

Total
3,194,500

 
 
 
 
Average price
 
 
 
 
$
12.85

Gasoline Crack Spread Swap Contracts
At December 31, 2017, the Company had the following derivatives related to gasoline crack spread sales in its fuel products segment, none of which are designated as hedges:
Gasoline Crack Spread Swap Contracts by Expiration Dates
Barrels Sold
 
BPD
 
Average Swap
($/Bbl)
First Quarter 2018
826,000

 
9,178

 
$
12.27

Total
826,000

 
 
 
 
Average price
 
 
 
 
$
12.27

Gasoline Swap Contracts
At December 31, 2017, the Company had the following derivatives related to gasoline swap sales in its fuel products segment, none of which are designated as hedges:
Gasoline Swap Contracts by Expiration Dates
Barrels Sold
 
 BPD
 
Average Swap
($/Bbl)
First Quarter 2018
14,000

 
156

 
$
61.35

Total
14,000

 
 
 
 
Average price
 
 
 
 
$
61.35


25
Table of Contents

Diesel Crack Spread Swap Contracts
At June 30, 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)
Third Quarter 2018
184,000

 
2,000

 
$
24.30

Fourth Quarter 2018
184,000

 
2,000

 
$
24.75

First Quarter 2019
90,000

 
1,000

 
$
26.80

Second Quarter 2019
91,000

 
1,000

 
$
26.80

Third Quarter 2019
92,000

 
1,000

 
$
26.80

Fourth Quarter 2019
92,000

 
1,000

 
$
26.80

Total
733,000

 
 
 
 
Average price
 
 
 
 
$
26.04

At December 31, 2017, the Company had the following derivatives related to diesel crack spread sales in its fuel products segment, none of which are designated as hedges:
Diesel Crack Spread Swap Contracts by Expiration Dates
Barrels Sold
 
BPD
 
Average Swap
($/Bbl)
First Quarter 2018
826,000

 
9,178

 
$
17.58

Total
826,000

 
 
 
 
Average price
 
 
 
 
$
17.58

Diesel Swap Contracts
At December 31, 2017, the Company had the following derivatives related to diesel swap sales in its fuel products segment, none of which are designated as hedges:
Diesel Swap Contracts by Expiration Dates
Barrels Sold
 
 BPD
 
Average Swap
($/Bbl)
First Quarter 2018
14,000

 
156

 
$
66.35

Total
14,000

 
 
 
 
Average price
 
 
 
 
$
66.35

Diesel Percentage Basis Crack Spread Swap Contracts
The Company has entered into 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 June 30, 2018, 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)
First Quarter 2019
450,000

 
5,000

 
138.75
%
Second Quarter 2019
455,000

 
5,000

 
138.75
%
Third Quarter 2019
460,000

 
5,000

 
138.75
%
Fourth Quarter 2019
460,000

 
5,000

 
138.75
%
Total
1,825,000

 
 
 
 
Average percentage
 
 
 
 
138.75
%


26
Table of Contents

11. Fair Value Measurements
The Company uses a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value. Observable inputs are from sources independent of the Company. Unobservable inputs reflect the Company’s assumptions about the factors market participants would use in valuing the asset or liability developed based upon the best information available in the circumstances. These tiers include the following:
•
Level 1 — inputs include observable unadjusted quoted prices in active markets for identical assets or liabilities
•
Level 2 — inputs include other than quoted prices in active markets that are either directly or indirectly observable
•
Level 3 — inputs include unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions
In determining fair value, the Company uses various valuation techniques and prioritizes the use of observable inputs. The availability of observable inputs varies from instrument to instrument and depends on a variety of factors including the type of instrument, whether the instrument is actively traded and other characteristics particular to the instrument. For many financial instruments, pricing inputs are readily observable in the market, the valuation methodology used is widely accepted by market participants and the valuation does not require significant management judgment. For other financial instruments, pricing inputs are less observable in the marketplace and may require management judgment.
Recurring Fair Value Measurements
Derivative Assets and Liabilities
Derivative instruments are reported in the accompanying unaudited condensed consolidated financial statements at fair value. The Company’s derivative instruments consist of over-the-counter 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 June 30, 2018, the Company’s net assets and liabilities were impacted by an immaterial amount. As a result of applying the CVA at December 31, 2017, the Company’s net liabilities were reduced 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.
Pension Assets
Pension assets are reported at fair value in the accompanying unaudited condensed consolidated financial statements. At June 30, 2018, 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 10 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):
 
June 30, 2018
 
December 31, 2017
 
Level 1
 
Level 2
 
Level 3
 
Total
 
Level 1
 
Level 2
 
Level 3
 
Total
Assets:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Derivative assets:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Diesel crack spread swaps
$
—

 
$
—

 
$
1.8

 
$
1.8

 
$
—

 
$
—

 
$
—

 
$
—

Diesel percentage basis crack spread swaps
—

 
—

 
(0.2
)
 
(0.2
)
 
—

 
—

 
—

 
—

WCS crude oil basis swaps
—

 
—

 
0.6

 
0.6

 
—

 
—

 
—

 
—

WCS crude oil percentage basis swaps
—

 
—

 
(0.5
)
 
(0.5
)
 
—

 
—

 
—

 
—

Midland crude oil basis swaps
—

 
—

 
2.1

 
2.1

 
—

 
—

 
—

 
—

Total derivative assets
—


—


3.8


3.8

 
—

 
—

 
—

 
—

Pension plan investments
0.1

 
—

 
—

 
0.1

 
0.2

 
—

 
—

 
0.2

Total recurring assets at fair value
$
0.1


$
—


$
3.8


$
3.9


$
0.2


$
—


$
—


$
0.2

Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Derivative liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Inventory financing obligation
$
—

 
$
—

 
$
(11.3
)
 
$
(11.3
)
 
$
—

 
$
—

 
$
(4.4
)
 
$
(4.4
)
Crude oil swaps
—

 
—

 
—

 
—

 
—

 
—

 
0.3

 
0.3

WCS crude oil percentage basis swaps
—

 
—

 
(0.3
)
 
(0.3
)
 
—

 
—

 
—

 
—

Midland crude oil basis swaps
—

 
—

 
0.8

 
0.8

 
—

 
—

 
—

 
—

Gasoline swaps
—

 
—

 
—

 
—

 
—

 
—

 
(0.2
)
 
(0.2
)
Gasoline crack spread swaps
—

 
—

 
—

 
—

 
—

 
—

 
(1.8
)
 
(1.8
)
Diesel swaps
—

 
—

 
—

 
—

 
—

 
—

 
(0.2
)
 
(0.2
)
Diesel crack spread swaps
—

 
—

 
—

 
—

 
—

 
—

 
(4.1
)
 
(4.1
)
Diesel percentage basis crack spread swaps
—

 
—

 
(0.6
)
 
(0.6
)
 
—

 
—

 
—

 
—

Total derivative liabilities
—

 
—

 
(11.4
)
 
(11.4
)
 
—

 
—

 
(10.4
)
 
(10.4
)
RINs Obligation
—

 
(5.8
)
 
—

 
(5.8
)
 
—

 
(59.1
)
 
—

 
(59.1
)
Liability Awards
(9.1
)
 
—

 
—

 
(9.1
)
 
(5.6
)
 
—

 
—

 
(5.6
)
Total recurring liabilities at fair value
$
(9.1
)
 
$
(5.8
)
 
$
(11.4
)
 
$
(26.3
)
 
$
(5.6
)
 
$
(59.1
)
 
$
(10.4
)
 
$
(75.1
)
The table below sets forth a summary of net changes in fair value of the Company’s Level 3 financial assets and liabilities (in millions):
 
Six Months Ended June 30,
 
2018
 
2017
Fair value at January 1,
$
(10.4
)
 
$
(14.0
)
Realized loss on derivative instruments
2.1

 
4.9

Unrealized gain on derivative instruments
2.8

 
11.9

Settlements
(2.1
)
 
(4.8
)
Fair value at June 30,
$
(7.6
)
 
$
(2.0
)
Total gain included in net income (loss) attributable to changes in unrealized gain relating to financial assets and liabilities held as of June 30,
$
2.8

 
$
11.9

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, in the event that the Company was required to measure and record such assets at fair value within its unaudited condensed consolidated financial statements.
The Company’s investment in FHC is a non-marketable equity security without a readily determinable fair value. The Company records this investment without a readily determinable fair value 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.
Estimated Fair Value of Financial Instruments
Cash, cash equivalents and restricted cash
The carrying value of cash, cash equivalents and restricted cash is each considered to be representative of its fair value.
Debt
The estimated fair value of long-term debt at June 30, 2018 and December 31, 2017, consists primarily of senior notes. The estimated aggregate fair value of the Company’s senior notes defined as Level 1 was based upon quoted market prices in an active market. The estimated aggregate fair value of the Company’s senior secured notes classified as Level 2 was based upon directly observable inputs. The carrying value of borrowings, if any, under the Company’s revolving credit facility, capital lease obligations and other obligations approximate their fair values as determined by discounted cash flows and are classified as Level 3. See Note 9 - “Long-Term Debt” for further information on long-term debt.
The Company’s carrying and estimated fair value of the Company’s financial instruments, carried at adjusted historical cost were as follows (in millions):
 
 
 
June 30, 2018
 
December 31, 2017
 
Level
 
Fair Value
 
Carrying Value
 
Fair Value
 
Carrying Value
Financial Instrument:
 
 
 
 
 
 
 
 
 
Senior notes
1
 
$
1,573.0

 
$
1,558.5

 
$
1,576.5

 
$
1,556.4

Senior notes
2
 
$
—

 
$
—

 
$
456.4

 
$
387.6

Revolving credit facility
3
 
$
0.1

 
$
0.1

 
$
0.2

 
$
0.2

Capital lease and other obligations
3
 
$
48.1

 
$
48.1

 
$
50.6

 
$
50.6


27
Table of Contents

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 June 30,
 
Six Months Ended June 30,
 
2018
 
2017
 
2018
 
2017
Numerator for basic and diluted earnings per limited partner unit:
 
 
 
 
 
 
 
Net income (loss) from continuing operations
$
(51.2
)
 
$
12.0

 
$
(54.1
)
 
$
13.5

Less:
 
 
 
 
 
 
 
General partner’s interest in net income (loss) from continuing operations
(1.0
)
 
0.3

 
(1.1
)
 
0.3

Non-vested share based payments
—

 
0.2

 
—

 
0.2

Net income (loss) from continuing operations available to limited partners
$
(50.2
)
 
$
11.5

 
$
(53.0
)
 
$
13.0

Net loss from discontinued operations available to limited partners
(0.7
)
 
(2.3
)
 
(2.6
)
 
(9.9
)
Net income (loss) available to limited partners
$
(50.9
)
 
$
9.2

 
$
(55.6
)
 
$
3.1

 
 
 
 
 
 
 
 
Denominator for earnings per limited partner unit:
 
 
 
 
 
 
 
Basic weighted average limited partner units outstanding
77,730,458

 
77,554,815

 
77,644,262

 
77,485,058

Effect of dilutive securities:
 
 
 
 
 
 
 
Incremental Units
—

 
159,297

 
—

 
240,598

Diluted weighted average limited partner units outstanding (1)
77,730,458

 
77,714,112

 
77,644,262

 
77,725,656

Limited partners’ interest basic and diluted net income (loss) per unit:
 
 
 
 
 
 
 
From continuing operations
$
(0.64
)
 
$
0.15

 
$
(0.68
)
 
$
0.17

From discontinued operations
(0.01
)
 
(0.03
)
 
(0.03
)
 
(0.13
)
Limited partners’ interest
$
(0.65
)
 
$
0.12

 
$
(0.71
)
 
$
0.04

 
(1) 
Total diluted weighted average limited partner units outstanding excludes 0.3 million for the three and six months ended June 30, 2018, consisting of unvested phantom units.
13. Segments and Related Information
a. Segment Reporting
The Company manages its business in two operating segments, which are grouped on the basis of similar product, market and operating factors into the following reportable segments:
•
Specialty Products. The specialty products segment is our 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 2 and PADD 4 areas within the U.S.
Prior to the sale of Anchor, as disclosed in Note 5 - “Discontinued Operations”, the Company reported an oilfield services segment, which was solely comprised of Anchor. As a result of Anchor’s classification as a discontinued operation, the Company has removed the oilfield services segment.
The accounting policies of the reporting segments are the same as those described in the summary of significant accounting policies as disclosed in Note 2 — “Summary of Significant Accounting Policies” in Part II, Item 8 “Financial Statements and Supplementary Data” of the Company’s 2017 Annual Report, except that the disaggregated financial results for the reporting segments have been prepared using a management approach, which is consistent with the basis and manner in which management internally disaggregates financial information for the purposes of assisting internal operating decisions. The Company accounts for intersegment sales and transfers at cost plus a specified mark-up. The Company evaluates performance based upon Adjusted EBITDA (a non-GAAP financial measure). The Company defines Adjusted EBITDA for any period as: (1) net income (loss); plus (2)(a) interest expense (including debt issuance and extinguishment costs); (b) income taxes; (c) depreciation and amortization; (d) impairment; (e) unrealized losses from mark to market accounting for hedging activities; (f) realized gains under derivative

28
Table of Contents

instruments excluded from the determination of net income (loss); (g) non-cash equity-based compensation expense and other non-cash items (excluding items such as accruals of cash expenses in a future period or amortization of a prepaid cash expense) that were deducted in computing net income (loss); (h) debt refinancing fees, premiums and penalties; (i) any net loss realized in connection with an asset sale that was deducted in computing net income (loss) and (j) all extraordinary, unusual or non-recurring items of gain or loss, or revenue or expense; minus (3)(a) unrealized gains from mark to market accounting for hedging activities; (b) realized losses under derivative instruments excluded from the determination of net income and (c) other non-recurring expenses and unrealized items that reduced net income (loss) for a prior period, but represent a cash item in the current period.
The Company manages its assets on a total company basis, not by segment. Therefore, management does not review any asset information by segment and, accordingly, the Company does not report asset information by segment.
Reportable segment information for the three months ended June 30, 2018 and 2017, is as follows (in millions):
Three Months Ended June 30, 2018
Specialty
Products
 
Fuel
Products
 
Combined
Segments
 
Eliminations
 
Consolidated
Total
Sales:
 
 
 
 
 
 
 
 
 
External customers
$
382.6

 
$
562.9

 
$
945.5

 
$
—

 
$
945.5

Intersegment sales
—

 
16.1

 
16.1

 
(16.1
)
 
—

Total sales
$
382.6

 
$
579.0

 
$
961.6

 
$
(16.1
)
 
$
945.5

Adjusted EBITDA
$
53.7

 
$
25.6

 
$
79.3

 
$
—

 
$
79.3

Reconciling items to net loss:
 
 
 
 
 
 
 
 
 
Depreciation and amortization
12.7

 
19.5

 
32.2

 
—

 
32.2

Realized loss on derivatives, not reflected in net loss
0.4

 
1.7

 
2.1

 
—

 
2.1

Unrealized gain on derivatives
 
 
 
 
 
 
 
 
(0.8
)
Interest expense
 
 
 
 
 
 
 
 
37.5

Debt extinguishment costs
 
 
 
 
 
 
 
 
58.2

Equity based compensation and other items
 
 
 
 
 
 
 
 
0.5

Income tax expense
 
 
 
 
 
 
 
 
0.8

Net loss from continuing operations
 
 
 
 
 
 
 
 
$
(51.2
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Three Months Ended June 30, 2017
Specialty
Products
 
Fuel
Products
 
Combined
Segments
 
Eliminations
 
Consolidated
Total
Sales:
 
 
 
 
 
 
 
 
 
External customers
$
343.1

 
$
623.9

 
$
967.0

 
$
—

 
$
967.0

Intersegment sales
0.1

 
17.4

 
17.5

 
(17.5
)
 
—

Total sales
$
343.2

 
$
641.3

 
$
984.5

 
$
(17.5
)
 
$
967.0

Adjusted EBITDA
$
67.1

 
$
34.0

 
$
101.1

 
$
—

 
$
101.1

Reconciling items to net income:
 
 
 
 
 
 
 
 
 
Depreciation and amortization
15.9

 
27.8

 
43.7

 
—

 
43.7

Unrealized gain on derivatives
 
 
 
 
 
 
 
 
(1.3
)
Interest expense
 
 
 
 
 
 
 
 
44.5

Equity based compensation and other items
 
 
 
 
 
 
 
 
2.2

Net income from continuing operations
 
 
 
 
 
 
 
 
$
12.0


29
Table of Contents

Reportable segment information for the six months ended June 30, 2018 and 2017, is as follows (in millions):
Six Months Ended June 30, 2018
Specialty
Products
 
Fuel
Products
 
Combined
Segments
 
Eliminations
 
Consolidated
Total
Sales:
 
 
 
 
 
 
 
 
 
External customers
$
704.4

 
$
991.6

 
$
1,696.0

 
$
—

 
$
1,696.0

Intersegment sales
—

 
25.9

 
25.9

 
(25.9
)
 
—

Total sales
$
704.4

 
$
1,017.5

 
$
1,721.9

 
$
(25.9
)
 
$
1,696.0

Loss from unconsolidated affiliates
$
(3.7
)
 
$
—

 
$
(3.7
)
 
$
—

 
$
(3.7
)
Adjusted EBITDA
$
91.4

 
$
64.3

 
$
155.7

 
$
—

 
$
155.7

Reconciling items to net loss:
 
 
 
 
 
 
 
 
 
Depreciation and amortization
27.0

 
38.2

 
65.2

 
—

 
65.2

Realized loss on derivatives, not reflected in net loss
0.4

 
1.7

 
2.1

 
—

 
2.1

Unrealized gain on derivatives
 
 
 
 
 
 
 
 
(2.8
)
Interest expense
 
 
 
 
 
 
 
 
82.7

Debt extinguishment costs
 
 
 
 
 
 
 
 
58.8

Equity based compensation and other items
 
 
 
 
 
 
 
 
3.2

Income tax expense
 
 
 
 
 
 
 
 
0.6

Net loss from continuing operations
 
 
 
 
 
 
 
 
$
(54.1
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Six Months Ended June 30, 2017
Specialty
Products
 
Fuel
Products
 
Combined
Segments
 
Eliminations
 
Consolidated
Total
Sales:
 
 
 
 
 
 
 
 
 
External customers
$
680.3

 
$
1,173.2

 
$
1,853.5

 
$
—

 
$
1,853.5

Intersegment sales
0.2

 
32.6

 
$
32.8

 
(32.8
)
 
$
—

Total sales
$
680.5

 
$
1,205.8

 
$
1,886.3

 
$
(32.8
)
 
$
1,853.5

Adjusted EBITDA
$
112.7

 
$
70.8

 
183.5

 
$
—

 
$
183.5

Reconciling items to net income:
 
 
 
 
 
 
 
 
 
Depreciation and amortization
32.9

 
55.3

 
88.2

 
—

 
88.2

Impairment charges
0.4

 
—

 
0.4

 
—

 
0.4

Unrealized gain on derivatives
 
 
 
 
 
 
 
 
(11.9
)
Interest expense
 
 
 
 
 
 
 
 
88.4

Equity based compensation and other items
 
 
 
 
 
 
 
 
5.0

Income tax benefit
 
 
 
 
 
 
 
 
(0.1
)
Net income from continuing operations
 
 
 
 
 
 
 
 
$
13.5


b. Geographic Information
International sales accounted for less than 10% of consolidated sales in each of the three and six months ended June 30, 2018 and 2017. Substantially all of the Company’s long-lived assets are domestically located.

30
Table of Contents

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 segment for the three months ended June 30, 2018 and 2017 (dollars in millions):
 
Three Months Ended June 30,
 
2018
 
2017
Specialty products:
 
 
 
 
 
 
 
Lubricating oils
$
165.5

 
17.5
%
 
$
153.1

 
15.8
%
Solvents
94.0

 
9.9
%
 
68.6

 
7.1
%
Waxes
28.1

 
3.0
%
 
29.0

 
3.0
%
Packaged and synthetic specialty products
72.9

 
7.7
%
 
73.2

 
7.6
%
Other
22.1

 
2.3
%
 
19.2

 
2.0
%
Total
$
382.6

 
40.5
%
 
$
343.1

 
35.5
%
Fuel products:
 
 
 
 
 
 
 
Gasoline
$
187.8

 
19.9
%
 
$
247.4

 
25.6
%
Diesel
250.7

 
26.5
%
 
210.2

 
21.7
%
Jet fuel
20.9

 
2.2
%
 
32.8

 
3.4
%
Asphalt, heavy fuel oils and other
103.5

 
10.9
%
 
133.5

 
13.8
%
Total
$
562.9

 
59.5
%
 
$
623.9

 
64.5
%
Consolidated sales
$
945.5

 
100.0
%
 
$
967.0

 
100.0
%
The following table sets forth the major product category sales for the six months ended June 30, 2018 and 2017 (dollars in millions):
 
Six Months Ended June 30,
 
2018
 
2017
Specialty products:
 
 
 
 
 
 
 
Lubricating oils
$
301.7

 
17.8
%
 
$
304.4

 
16.4
%
Solvents
166.0

 
9.8
%
 
136.1

 
7.3
%
Waxes
57.7

 
3.4
%
 
60.0

 
3.2
%
Packaged and synthetic specialty products
140.9

 
8.3
%
 
142.5

 
7.7
%
Other
38.1

 
2.2
%
 
37.3

 
2.1
%
Total
$
704.4

 
41.5
%
 
$
680.3

 
36.7
%
Fuel products:
 
 
 
 
 
 
 
Gasoline
$
337.6

 
19.9
%
 
$
475.6

 
25.7
%
Diesel
424.0

 
25.0
%
 
417.0

 
22.5
%
Jet fuel
50.8

 
3.0
%
 
70.4

 
3.8
%
Asphalt, heavy fuel oils and other
179.2

 
10.6
%
 
210.2

 
11.3
%
Total
$
991.6

 
58.5
%
 
$
1,173.2

 
63.3
%
Consolidated sales
$
1,696.0

 
100.0
%
 
$
1,853.5

 
100.0
%
d. Major Customers
During the three and six months ended June 30, 2018 and 2017, the Company had no customer that represented 10% or greater of consolidated sales.
e. Major Suppliers
During the three months ended June 30, 2018 and 2017, the Company had two suppliers that supplied approximately 59.0% and 66.9%, respectively, of its crude oil supply. During the six months ended June 30, 2018 and 2017, the Company had two suppliers that supplied approximately 59.6% and 66.5%, respectively, of its crude oil supply.

31
Table of Contents

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 six months ended June 30, 2018 and 2017. In addition, as discussed in Note 1 and Note 5 to the Unaudited Condensed Consolidated Financial Statements, we closed the Superior Transaction and the Anchor Transaction on November 8, 2017 and November 21, 2017, respectively. The historical results of operations of the Superior Refinery are contained in our financial position and results through November 7, 2017. As a result of the Anchor Transaction, we classified its results of operations and the assets and liabilities of 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 2017 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 two segments: our core specialty products segment as well as our fuel products 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, TruFuel and Quantum 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.
Second Quarter 2018 Update
Outlook and Trends
Commodity markets and corresponding fluctuations in product margins have been mixed during the six months ended June 30, 2018, with the average price per barrel of New York Mercantile Exchange West Texas Intermediate (“NYMEX WTI”) crude oil increasing more than 8% in the second quarter of 2018 as compared to the first quarter of 2018. We expect volatility to continue for the remainder of 2018. Below are factors that have impacted or may impact our results of operations during 2018:
•
Gasoline margins are expected to increase in response to the higher domestic demand associated with the summer driving season. Diesel margins have been positively impacted by decreases in supply and are expected to be stable.
•
Environmental regulations continue to affect our margins in the form of the cost of Renewable Identification Numbers (“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 48% decrease in the price of RINs during the second quarter 2018 favorably affected our results of operations. 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.
•
Asphalt demand is expected to increase due to the seasonality of the road construction and roofing industries, which have shown increased demand in prior years.
•
Canadian heavy sour crude oil discounts are expected to remain wide over the intermediate term as sour crude oil remains oversupplied. Sweet crude oil discounts are expected to widen for on-shore domestic sweet crude oil production especially for the crude oils facing transportation constraints such as Midland WTI. Processing heavy sour crude oil and Midland WTI crude oil in our refining system results in a lower overall delivered cost of crude oil.
•
Specialty products margins 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 invest in our specialty products segment while divesting non-core businesses. Accordingly, 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. However, 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 these assets or non-core 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

32

leverage an existing core competency and that have an identifiable competitive advantage we can exploit as the new owner.
Financial Results
We reported a net loss from continuing operations of $51.2 million in the second quarter 2018, versus net income from continuing operations of $12.0 million in the second quarter 2017. We reported Adjusted EBITDA from continuing operations (as defined in “Non-GAAP Financial Measures”) of $79.3 million in the second quarter 2018, versus $101.1 million in the second quarter 2017. We used cash in continuing operations of $23.3 million in the second quarter 2018, versus $20.1 million in the second quarter 2017. Our continuing operations $51.2 million net loss for the second quarter 2018 included $58.2 million of debt extinguishment costs.
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 GAAP.
Commodity markets remained volatile in the second quarter 2018, contributing to fluctuations in refined product margins. The average price of NYMEX WTI crude oil increased over 41.0% in the second quarter 2018, when compared to the prior year period. In the second quarter 2018, the average price differential per barrel between Western Canadian Select (“WCS”) crude oil and NYMEX WTI averaged $18 per barrel below NYMEX WTI, versus $9 per barrel below NYMEX WTI in the second quarter 2017. 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. In the second quarter 2018, we processed 25,500 barrels per day (“bpd”) of heavy Canadian crude oil, versus 41,600 bpd in the second quarter 2017, of which 25,200 was processed at the Great Falls refinery. In addition, we processed 10,500 bpd of WTI Midland crude oil in second quarter 2018.
Specialty products segment Adjusted EBITDA was $53.7 million in the second quarter 2018, versus $67.1 million in the second quarter 2017. Specialty products second quarter 2018 segment Adjusted EBITDA was impacted by rising feedstock costs, decreased sales volume as a result of decreased production at the Shreveport refinery and certain third-party processing facilities due to maintenance activities, partially offset by strong performance of the packaged and synthetic specialty products and solvents. Second quarter 2018 results were impacted by a $4.6 million favorable LCM inventory adjustment.
Fuel products segment Adjusted EBITDA was $25.6 million during the second quarter 2018, versus $34.0 million in the second quarter 2017, due primarily to the sale of the refinery in Superior, Wisconsin (“Superior Refinery”) in November 2017, partially offset by widening crack spreads and a widening in the WCS and WTI Midland differentials to NYMEX WTI. Second quarter 2018 results were impacted by a $9.4 million favorable LCM inventory adjustment.
For benchmarking purposes, we compare our per barrel refined fuel products margin to the U.S. Gulf Coast 2/1/1 crack spread (“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 second quarter 2018, the Gulf Coast crack spread averaged approximately $19 per barrel compared to approximately $15 per barrel in the prior year period, an approximate 27% increase. The Gulf Coast ULSD crack spread averaged approximately $20 per barrel during the second quarter 2018, compared to approximately $14 per barrel in the prior year period. The Gulf Coast gasoline crack spread averaged approximately $17 per barrel during the second quarter 2018, compared to approximately $16 per barrel in the prior year period.
In September 2017, we implemented the first phase of our new enterprise resource planning (“ERP”) software system, to provide better information and enable us to manage our business operations more effectively, including processing sales orders and invoicing, inventory control, purchasing and supply chain management and financial reporting. However, the implementation of our ERP system resulted in operating and reporting disruptions, including limitations on our ability to ship product and bill customers, project our inventory requirements, manage our supply chain, maintain current and complete books and records, maintain an effective internal control environment and meet external reporting deadlines. During the three and six months ended June 30, 2018, we incurred approximately $2.4 million and $6.1 million, respectively, of expenses related to the ERP implementation. A majority of the expenses were associated with stabilizing the ERP system. We expect that we will continue to incur costs related to our ERP system for the remainder of 2018 as we stabilize the system and then embark on a number of enhancements to achieve the expected results for the implementation.

33

Liquidity Update
As of June 30, 2018, we had total liquidity of $381.5 million comprised of $38.8 million of unrestricted cash and availability under our revolving credit facility of $342.7 million. As of June 30, 2018, we had a $373.6 million borrowing base, $30.8 million in outstanding standby letters of credit and approximately $0.1 million of 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.
In April 2018, we redeemed all of the $400.0 million in aggregate principal amount of 11.50% Senior Secured Notes due January 15, 2021 (“2021 Secured Notes”). The holders received a redemption price of 100.0% of the principal amount of the 2021 Secured Notes, plus accrued and unpaid interest thereon up to, but not including, April 9, 2018 (the “Redemption Date”), plus a Make Whole Premium (as defined in the Indenture, dated April 20, 2016, governing the 2021 Secured Notes). In conjunction with the redemption, we incurred debt extinguishment costs of $58.2 million, including $11.6 million of non-cash charges.
In May 2018, Pacific New Investment Limited (“PACNIL”) (an entity formed by us and The Heritage Group (“Heritage Group”), a related party) sold its investment in Shandong Hi-Speed Hainan Development Co., Ltd. (“Hi-Speed”) to the other owners. We received proceeds of $9.9 million for the sale.
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 U.S. Environmental Protection Agency (“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.
During the second quarter 2018, we recognized RINs expense of $1.9 million, compared to a gain of $16.5 million, for the second quarter 2017. For the full-year 2018, we anticipate our gross RINs obligation will decrease to 85 million RINs, given the recent divestiture of the Superior Refinery. Estimated RINs obligations remain subject to fluctuations in fuels production volumes during the full-year 2018. The gross RINs obligations exclude the potential for any subsequent hardship waivers.
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.
2018 Capital Spending Forecast
We estimate our capital expenditures will be between $80 million and $90 million in 2018.
Key Performance Measures
Our sales and net income 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 additional factors beyond our control. We monitor these risks and 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 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.

34
Table of Contents

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.

35
Table of Contents

Results of Operations for the Three and Six Months Ended June 30, 2018 and 2017
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 June 30,
 
Six Months Ended June 30,
 
2018
 
2017
 
% Change
 
2018
 
2017
 
% Change
 
(In bpd)
 
 
 
(In bpd)
 
 
Total sales volume (1)
102,484

 
141,154

 
(27.4
)%
 
95,298


135,343

 
(29.6
)%
Total feedstock runs (2)
98,704

 
136,552

 
(27.7
)%
 
91,637


134,370

 
(31.8
)%
Facility production: (3)
 
 
 
 


 
 
 
 
 


Specialty products:
 
 
 
 


 
 
 
 
 


Lubricating oils
13,755

 
15,914

 
(13.6
)%
 
11,904


15,539

 
(23.4
)%
Solvents
7,726

 
8,239

 
(6.2
)%
 
7,854


7,794

 
0.8
 %
Waxes
1,172

 
1,373

 
(14.6
)%
 
1,205


1,425

 
(15.4
)%
Packaged and synthetic specialty products (4)
2,458

 
2,551

 
(3.6
)%
 
2,448


2,559

 
(4.3
)%
Other
2,087

 
1,341

 
55.6
 %
 
1,898


1,692

 
12.2
 %
Total
27,198

 
29,418

 
(7.5
)%
 
25,309

 
29,009

 
(12.8
)%
Fuel products:
 
 
 
 


 
 
 
 
 
 
Gasoline
21,135

 
37,225

 
(43.2
)%
 
19,501


37,395

 
(47.9
)%
Diesel
27,993

 
34,787

 
(19.5
)%
 
25,534


33,904

 
(24.7
)%
Jet fuel
2,705

 
5,306

 
(49.0
)%
 
3,223


6,030

 
(46.6
)%
Asphalt, heavy fuels and other
20,869

 
33,699

 
(38.1
)%
 
18,909


31,569

 
(40.1
)%
Total
72,702

 
111,017

 
(34.5
)%
 
67,167

 
108,898

 
(38.3
)%
Total facility production (3)
99,900

 
140,435

 
(28.9
)%
 
92,476

 
137,907

 
(32.9
)%
_____________
(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 decrease in total sales volume for the three and six months ended June 30, 2018, as compared to the same periods in 2017, is due primarily to the divestiture of the Superior Refinery in November 2017 and decreased production at the Shreveport refinery and certain third-party processing facilities as a result of maintenance activities.
(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 decrease in total feedstock runs for the three and six months ended June 30, 2018, as compared to the same periods in 2017, is due primarily to the divestiture of the Superior refinery in November 2017 and decreased production at the Shreveport refinery and certain third-party processing facilities as a result of maintenance activities.
(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 six months ended June 30, 2018, as compared to the same periods in 2017, is due primarily to the operational items discussed above in footnote 2.
(4) 
Represents production of branded and packaged specialty products including the products from the Royal Purple, Bel-Ray and Calumet Packaging facilities.

36
Table of Contents

The following table reflects our 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 income (loss) and Net cash 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 June 30,
 
Six Months Ended June 30,
 
2018
 
2017
 
2018
 
2017
 
(In millions)
Sales
$
945.5

 
$
967.0

 
$
1,696.0

 
$
1,853.5

Cost of sales
822.1

 
823.3

 
1,459.4

 
1,580.3

Gross profit
123.4

 
143.7

 
236.6

 
273.2

Operating costs and expenses:
 
 
 
 
 
 
 
Selling
10.6

 
15.1

 
25.3

 
31.4

General and administrative
31.9

 
32.4

 
72.5

 
63.0

Transportation
33.0

 
35.6

 
63.3

 
71.3

Taxes other than income taxes
5.4

 
4.8

 
7.3

 
10.0

Asset impairment
—

 
—

 
—

 
0.4

Other operating (income) expense
(1.1
)
 
1.1

 
(16.7
)
 
3.0

Operating income
43.6

 
54.7

 
84.9

 
94.1

Other income (expense):
 
 
 
 
 
 
 
Interest expense
(37.5
)
 
(44.5
)
 
(82.7
)
 
(88.4
)
Debt extinguishment costs
(58.2
)
 
—

 
(58.8
)
 
—

Gain on derivative instruments
0.8

 
1.3

 
0.7

 
7.0

Other
0.9

 
0.5

 
2.4

 
0.7

Total other expense
(94.0
)
 
(42.7
)
 
(138.4
)
 
(80.7
)
Net income (loss) from continuing operations before income taxes
(50.4
)
 
12.0

 
(53.5
)
 
13.4

Income tax expense (benefit) from continuing operations
0.8

 
—

 
0.6

 
(0.1
)
Net income (loss) from continuing operations
$
(51.2
)
 
$
12.0

 
$
(54.1
)
 
$
13.5

Net loss from discontinued operations, net of tax
$
(0.7
)
 
$
(2.4
)
 
$
(2.6
)
 
$
(10.1
)
Net income (loss)
$
(51.9
)
 
$
9.6

 
$
(56.7
)
 
$
3.4

EBITDA
$
15.9

 
$
94.1

 
$
85.8

 
$
172.8

Adjusted EBITDA
$
78.9

 
$
101.6

 
$
153.9

 
$
180.3

Distributable Cash Flow
$
36.5

 
$
45.2

 
$
59.5

 
$
76.7

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 income (loss), our most directly comparable financial performance measure. We also provide a reconciliation of Distributable Cash Flow, Adjusted EBITDA and EBITDA to Net cash used in operating activities, our most directly comparable liquidity measure. Both Net loss and Net cash used in operating activities are calculated and presented in accordance with U.S. generally accepted accounting principles (“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

37
Table of Contents

distributions. We believe that excluding these transactions allows investors to meaningfully analyze trends and performance of our core cash operations.
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: (1) net income (loss); plus (2)(a) interest expense (including debt issuance and extinguishment costs); (b) income taxes; (c) depreciation and amortization; (d) impairment; (e) unrealized losses from mark to market accounting for hedging activities; (f) realized gains under derivative instruments excluded from the determination of net income (loss); (g) non-cash equity-based compensation expense and other non-cash items (excluding items such as accruals of cash expenses in a future period or amortization of a prepaid cash expense) that were deducted in computing net income (loss); (h) debt refinancing fees, premiums and penalties; (i)  any net loss realized in connection with an asset sale that was deducted in computing net income (loss) and (j) all extraordinary, unusual or non-recurring items of gain or loss, or revenue or expense; minus (3)(a) unrealized gains from mark to market accounting for hedging activities; (b) realized losses under derivative instruments excluded from the determination of net income (loss) and (c) other non-recurring expenses and unrealized items that reduced net income (loss) for a prior period, but represent a cash item in the current period.
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, 2022 and 2023 Notes (as defined in this Quarterly Report). We are required to report Consolidated Cash Flow to the holders of our 2021, 2022 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 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 income (loss) to EBITDA, Adjusted EBITDA and Distributable Cash Flow; Distributable Cash Flow, Adjusted EBITDA and EBITDA to Net cash used in operating activities; and Segment Adjusted EBITDA to EBITDA and Net income (loss) our most directly comparable GAAP financial performance and liquidity measures, for each of the periods indicated.

38
Table of Contents

 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2018
 
2017
 
2018
 
2017
 
(In millions)
Reconciliation of Net income (loss) to EBITDA, Adjusted EBITDA and Distributable Cash Flow:
 
Net income (loss)
$
(51.9
)
 
$
9.6

 
$
(56.7
)
 
$
3.4

Add:
 
 
 
 
 
 
 
Interest expense
37.5

 
44.5

 
82.7

 
88.4

Depreciation and amortization
29.5

 
40.9

 
59.2

 
82.0

Income tax expense (benefit)
0.8

 
(0.9
)
 
0.6

 
(1.0
)
EBITDA
$
15.9

 
$
94.1

 
$
85.8

 
$
172.8

Add:
 
 
 
 
 
 
 
Unrealized gain on derivative instruments
$
(0.8
)
 
$
(1.3
)
 
$
(2.8
)
 
$
(11.9
)
Realized loss on derivatives, not included in net income (loss) or settled in a prior period
2.1

 
—

 
2.1

 
—

Amortization of turnaround costs
2.7

 
6.6

 
6.0

 
14.0

Impairment charges
—

 
—

 
—

 
0.4

Debt extinguishment costs
58.2

 
—

 
58.8

 
—

Equity based compensation and other items
0.8

 
2.2

 
4.0

 
5.0

Adjusted EBITDA
$
78.9

 
$
101.6

 
$
153.9

 
$
180.3

Less:
 
 
 
 
 
 
 
Replacement and environmental capital expenditures (1)
$
5.0

 
$
5.6

 
$
11.6

 
$
10.9

Cash interest expense (2)
35.8

 
42.0

 
78.3

 
83.6

Turnaround costs
0.8

 
9.8

 
7.6

 
10.3

Loss from unconsolidated affiliates
—

 
(0.1
)
 
(3.7
)
 
(0.2
)
Income tax expense (benefit)
0.8

 
(0.9
)
 
0.6

 
(1.0
)
Distributable Cash Flow
$
36.5

 
$
45.2

 
$
59.5

 
$
76.7

 
(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.

39
Table of Contents

 
Six Months Ended June 30,
 
2018

2017
 
(In millions)
Reconciliation of Distributable Cash Flow, Adjusted EBITDA and EBITDA to Net cash used in operating activities:
 
 
 
Distributable Cash Flow
$
59.5

 
$
76.7

Add:
 
 
 
Replacement and environmental capital expenditures (1)
11.6

 
10.9

Cash interest expense (2)
78.3

 
83.6

Turnaround costs
7.6

 
10.3

Loss from unconsolidated affiliates
(3.7
)
 
(0.2
)
Income tax expense (benefit)
0.6

 
(1.0
)
Adjusted EBITDA
$
153.9

 
$
180.3

Less:



Unrealized gain on derivative instruments
$
(2.8
)
 
$
(11.9
)
Realized loss on derivatives, not included in net income (loss) or settled in a prior period
2.1

 
—

Amortization of turnaround costs
6.0

 
14.0

Impairment charges
—

 
0.4

Debt extinguishment costs
58.8

 
—

Equity based compensation and other items
4.0

 
5.0

EBITDA
$
85.8

 
$
172.8

Add:
 
 
 
Unrealized gain on derivative instruments
$
(2.8
)
 
$
(11.9
)
Cash interest expense (2)
(78.3
)
 
(83.6
)
Asset impairment
—

 
0.4

Equity based compensation
3.0

 
3.3

Lower of cost or market inventory adjustment
(15.0
)
 
(8.0
)
Loss from unconsolidated affiliates
3.7

 
0.2

Amortization of turnaround costs
6.0

 
14.0

Debt extinguishment costs
58.8

 
—

Income tax benefit (expense)
(0.6
)
 
1.0

Changes in assets and liabilities:
 
 
 
Accounts receivable
19.5

 
(50.7
)
Inventories
(2.6
)
 
(44.3
)
Other current assets
2.2

 
(2.1
)
Derivative activity
(0.3
)
 
(0.3
)
Turnaround costs
(7.6
)
 
(10.3
)
Accounts payable
(17.7
)
 
24.2

Accrued interest payable
(20.3
)
 
(0.1
)
Other current liabilities
(56.2
)
 
(44.8
)
Other
(0.9
)
 
4.6

Net cash used in operating activities
$
(23.3
)
 
$
(35.6
)
 
(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.

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Table of Contents

 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2018
 
2017
 
2018
 
2017
 
(In millions)
Reconciliation of Segment Adjusted EBITDA to EBITDA and Net income (loss):
 
 
 
 
 
Segment Adjusted EBITDA
 
 
 
 
 
 
 
Specialty products Adjusted EBITDA
$
53.7

 
$
67.1

 
$
91.4

 
$
112.7

Fuel products Adjusted EBITDA
25.6

 
34.0

 
64.3

 
70.8

Discontinued operations Adjusted EBITDA
(0.4
)
 
0.5

 
(1.8
)
 
(3.2
)
Total segment Adjusted EBITDA
$
78.9

 
$
101.6

 
$
153.9

 
$
180.3

Less:
 
 
 
 
 
 
 
Unrealized gain on derivative instruments
$
(0.8
)
 
$
(1.3
)
 
$
(2.8
)
 
$
(11.9
)
Realized loss on derivatives, not included in net income (loss) or settled in a prior period
2.1

 
—

 
2.1

 
—

Amortization of turnaround costs
2.7

 
6.6

 
6.0

 
14.0

Impairment charges
—

 
—

 
—

 
0.4

Debt extinguishment costs
58.2

 
—

 
58.8

 
—

Equity based compensation and other items
0.8

 
2.2

 
4.0

 
5.0

EBITDA
$
15.9

 
$
94.1

 
$
85.8

 
$
172.8

Less:
 
 
 
 
 
 
 
Interest expense
$
37.5

 
$
44.5

 
$
82.7

 
$
88.4

Depreciation and amortization
29.5

 
40.9

 
59.2

 
82.0

Income tax expense (benefit)
0.8

 
(0.9
)
 
0.6

 
(1.0
)
Net income (loss)
$
(51.9
)
 
$
9.6

 
$
(56.7
)
 
$
3.4



41
Table of Contents

Changes in Results of Operations for the Three Months Ended June 30, 2018 and 2017
Sales. Sales from continuing operations decreased $21.5 million, or 2.2%, to $945.5 million in the three months ended June 30, 2018, from $967.0 million in the same period in 2017. Sales for each of our principal product categories in these periods were as follows:
 
Three Months Ended June 30,
 
2018
 
2017
 
% Change
 
(Dollars in millions, except barrel and per barrel data)
Sales by segment:
 
 
 
 
 
Specialty products:
 
 
 
 
 
Lubricating oils
$
165.5

 
$
153.1

 
8.1
 %
Solvents
94.0

 
68.6

 
37.0
 %
Waxes
28.1

 
29.0

 
(3.1
)%
Packaged and synthetic specialty products (1)
72.9

 
73.2

 
(0.4
)%
Other (2)
22.1

 
19.2

 
15.1
 %
Total specialty products
$
382.6

 
$
343.1

 
11.5
 %
Total specialty products sales volume (in barrels)
2,371,000

 
2,460,000

 
(3.6
)%
Average specialty products sales price per barrel
$
161.37

 
$
139.47

 
15.7
 %
 
 
 
 
 
 
Fuel products:
 
 
 
 
 
Gasoline
$
187.8

 
$
247.4

 
(24.1
)%
Diesel
250.7

 
210.2

 
19.3
 %
Jet fuel
20.9

 
32.8

 
(36.3
)%
Asphalt, heavy fuel oils and other (3)
103.5

 
133.5

 
(22.5
)%
Total fuel products
$
562.9

 
$
623.9

 
(9.8
)%
Total fuel products sales volume (in barrels)
6,955,000

 
10,385,000

 
(33.0
)%
Average fuel products sales price per barrel
$
80.93

 
$
60.08

 
34.7
 %
 
 
 
 
 
 
Total sales
$
945.5

 
$
967.0

 
(2.2
)%
Total specialty and fuel products sales volume (in barrels)
9,326,000

 
12,845,000

 
(27.4
)%
 
(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, Superior, San Antonio and Great Falls refineries and crude oil sales from the Superior and San Antonio refineries to third-party customers.
The components of the $39.5 million increase in specialty products segment sales for the three months ended June 30, 2018, as compared to the three months ended June 30, 2017, were as follows:
 
Dollar Change
 
(In millions)
Volume
$
(12.5
)
Sales price
52.0

Total specialty products segment sales increase
$
39.5

Specialty products segment sales increased $39.5 million period over period, or 11.5%, primarily due to an increase in the average selling price per barrel, partially offset by a decrease in sales volume. Sales increased $52.0 million compared to the second quarter 2017 due to a $21.90 increase in the average selling price per barrel driven by an over $20.00 increase in the average cost of crude oil per barrel. Average selling prices per barrel increased in most product lines due to market conditions. The decrease in sales volume was due primarily to decreased production at the Shreveport refinery and certain third-party processing facilities as

42
Table of Contents

a result of maintenance activities, partially offset by increased sales volumes of packaged and synthetic specialty products and solvents due to market conditions.
The components of the $61.0 million decrease in fuel products segment sales for the three months ended June 30, 2018, as compared to the three months ended June 30, 2017, were as follows:
 
Dollar Change
 
(In millions)
Divestiture impact
$
(175.9
)
Volume
(28.5
)
Sales price
143.4

Total fuel products segment sales decrease
$
(61.0
)
Fuel products segment sales decreased $61.0 million period over period, or 9.8%, primarily due to the sale of the Superior Refinery in November 2017 and decreased sales volume, partially offset by an increase in the average selling price per barrel. The average selling price per barrel increased $20.85, or 34.7%, resulting in a $143.4 million increase in sales, compared to an $18.00 increase in the average cost of crude oil per barrel. The increase in the average selling price per barrel was primarily due to market conditions. Sales volume decreased 33.0% primarily due to the divestiture of the Superior Refinery in November 2017 and decreased production at the Shreveport refinery.
Gross Profit. Gross profit from continuing operations decreased $20.3 million, or 14.1%, to $123.4 million in the three months ended June 30, 2018, from $143.7 million in the same period in 2017. Gross profit for our specialty and fuel products segments were as follows:
 
Three Months Ended June 30,
 
2018
 
2017
 
% Change
 
(Dollars in millions, except per barrel data)
Gross profit by segment:
 
 
 
 
 
Specialty products:
 
 
 
 
 
Gross profit
$
88.0

 
$
103.0

 
(14.6
)%
Percentage of sales
23.0
%
 
30.0
%
 
 
Specialty products gross profit per barrel
$
37.12

 
$
41.87

 
(11.3
)%
Fuel products:
 
 
 
 
 
Gross profit
$
35.4

 
$
40.7

 
(13.0
)%
Percentage of sales
6.3
%
 
6.5
%
 
 
Fuel products gross profit per barrel
$
5.09

 
$
3.92

 
29.8
 %
Total gross profit
$
123.4

 
$
143.7

 
(14.1
)%
Percentage of sales
13.1
%
 
14.9
%
 
 
The components of the $15.0 million decrease in specialty products segment gross profit for the three months ended June 30, 2018, as compared to the three months ended June 30, 2017, were as follows:
 
Dollar Change
 
(In millions)
Three months ended June 30, 2017 reported gross profit
$
103.0

Cost of materials
(64.6
)
Volume
(5.5
)
Operating costs
(1.4
)
LCM inventory adjustment
4.5

Sales price
52.0

Three months ended June 30, 2018 reported gross profit
$
88.0

The decrease in specialty products segment gross profit of $15.0 million for the three months ended June 30, 2018, as compared to the same period in 2017, was due primarily to increased cost of materials, decreased sales volume and increased operating costs, partially offset by an increase in the average selling price per barrel and a decrease in the unfavorable LCM adjustment. Sales price and cost of materials, net, decreased gross profit by $12.6 million, as the average selling price per barrel increased $21.90 compared to an increase of approximately $20.00 in the average cost of crude oil per barrel. The decrease in sales volume was due primarily to decreased production at the Shreveport refinery and certain third-party processing facilities, partially offset by

43
Table of Contents

increased sales volumes of packaged and synthetic specialty products and solvents due to market conditions that resulted in a shift in product mix. The increase in operating costs was primarily due to increased wages and benefits and increased repairs and maintenance, partially offset by decreased depreciation and amortization.
The components of the $5.3 million decrease in fuel products segment gross profit for the three months ended June 30, 2018, as compared to the three months ended June 30, 2017, were as follows:
 
Dollar Change
 
(In millions)
Three months ended June 30, 2017 reported gross profit
$
40.7

Cost of materials
(105.7
)
Divestiture impact
(52.3
)
Volume
(5.2
)
Operating costs
(4.7
)
LCM inventory adjustment
9.2

RINs expense
10.0

Sales price
143.4

Three months ended June 30, 2018 reported gross profit
$
35.4

The decrease in fuel products segment gross profit of $5.3 million for the three months ended June 30, 2018, as compared to the same period in 2017, was primarily due to the sale of the Superior Refinery in November 2017, decreased sales volume and increased operating costs, partially offset by widening crack spreads, widening crude oil differentials, a $9.2 million decrease in the unfavorable LCM inventory adjustment and a decrease in RINs expense. During the second quarter 2018 period, the average cost of crude oil per barrel increased over $18.00 and the average selling price per barrel increased by $20.85. Decreased volume was primarily due to the sale of the Superior Refinery as well as a decrease in production at the Shreveport refinery. The increase in operating costs was primarily due to increased wages and benefits and increased repairs and maintenance, partially offset by decreased depreciation and amortization and decreased utilities. The decrease in RINs expense primarily resulted from decreased RINs market pricing, partially offset by a reduction in the RINs liability as a result of receiving approval for the small refinery exemption from the EPA for certain refineries in 2017.
Selling. Selling expenses from continuing operations decreased $4.5 million, or 29.8%, to $10.6 million in the three months ended June 30, 2018, from $15.1 million in the same period in 2017. The decrease was due primarily to a $3.3 million decrease in bad debt expense, $1.2 million decrease in depreciation and amortization, a $0.8 million decrease in advertising expense, a $0.4 million decrease in commissions and decreases related to the sale of the Superior Refinery, partially offset by an increase of $1.4 million in professional fees.
General and administrative. General and administrative expenses from continuing operations decreased $0.5 million, or 1.5%, to $31.9 million in the three months ended June 30, 2018, from $32.4 million in the same period in 2017. The decrease was primarily due to a $5.2 million decrease in professional fees including ERP costs and decreases related to the sale of the Superior Refinery, partially offset by a $2.0 million increase in depreciation and amortization, a $1.4 million increase in salaries and benefits, a $1.2 million increase in information technology hardware and maintenance expenses and a $0.8 million increase in legal settlements.
Transportation. Transportation expenses from continuing operations decreased $2.6 million, or 7.3%, to $33.0 million in the three months ended June 30, 2018, from $35.6 million in the same period in 2017. This decrease was due primarily to the sale of the Superior Refinery, decreased freight rates, decreased specialty products sales volumes and the continued optimization of our transportation logistics system.
Interest expense. Interest expense from continuing operations decreased $7.0 million, or 15.7%, to $37.5 million in the three months ended June 30, 2018, from $44.5 million in the same period in 2017, due primarily to the redemption of the 2021 Secured Notes in April 2018 and decreased revolving credit facility borrowings, partially offset by an increase in interest related to the Supply and Offtake Agreements (defined below) and decreased capitalized interest.
Debt extinguishment costs. The Company incurred debt extinguishment costs from continuing operations of $58.2 million during the three months ended June 30, 2018 related to the redemption of the 2021 Secured Notes which were redeemed in April 2018. There was no comparable activity during the same period in 2017.

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Table of Contents

Derivative activity. The following table details the impact of our derivative instruments from continuing operations on the unaudited condensed consolidated statements of operations for the three months ended June 30, 2018 and 2017:
 
Three Months Ended June 30,
 
2018
 
2017
 
(In millions)
Derivative loss reflected in cost of sales
$
(2.1
)
 
$
—

Derivative loss reflected in gross profit
$
(2.1
)
 
$
—

 


 


Unrealized gain on derivative instruments
$
0.8


$
1.3

Total derivative gain (loss) reflected in the unaudited condensed consolidated statements of operations
$
(1.3
)
 
$
1.3

Gain on derivative instruments. Gain on derivative instruments decreased $0.5 million to $0.8 million in the three months ended June 30, 2018, from $1.3 million in the prior year period. The change was primarily due to an increase in unrealized losses of $2.0 million on embedded derivatives associated with our Supply and Offtake Agreements (defined below), partially offset by a $1.5 million increase in unrealized gains on crude oil and diesel swaps used to economically hedge purchases and sales driven by market conditions.
Net loss from discontinued operations. Net loss from discontinued operations was $0.7 million for three months ended June 30, 2018 compared to $2.4 million in three months ended June 30, 2017. 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 $0.7 million for the three months ended June 30, 2018 relates to a legal reserve and lease terminations. The 2017 discontinued operations represents the operating results and were impacted by increased sales volume driven by an increase in rig count. Increases in crude oil and natural gas prices impacted customers’ drilling and production activities during 2017. Refer to Note 5 - “Discontinued Operations” in Part I, Item 1 “Financial Statements - Notes to Unaudited Condensed Consolidated Financial Statements” for additional information.

45
Table of Contents

Changes in Results of Operations for the Six Months Ended June 30, 2018 and 2017
Sales. Sales from continuing operations decreased $157.5 million, or 8.5%, to $1,696.0 million in the six months ended June 30, 2018, from $1,853.5 million in the same period in 2017. Sales for each of our principal product categories in these periods were as follows:
 
Six Months Ended June 30,
 
2018
 
2017
 
% Change
 
(Dollars in millions, except barrel and per barrel data)
Sales by segment:
 
 
 
 
 
Specialty products:
 
 
 
 
 
Lubricating oils
$
301.7

 
$
304.4

 
(0.9
)%
Solvents
166.0

 
136.1

 
22.0
 %
Waxes
57.7

 
60.0

 
(3.8
)%
Packaged and synthetic specialty products (1)
140.9

 
142.5

 
(1.1
)%
Other (2)
38.1

 
37.3

 
2.1
 %
Total specialty products
$
704.4

 
$
680.3

 
3.5
 %
Total specialty products sales volume (in barrels)
4,473,000

 
5,010,000

 
(10.7
)%
Average specialty products sales price per barrel
$
157.48

 
$
135.79

 
16.0
 %
 
 
 
 
 
 
Fuel products:
 
 
 
 
 
Gasoline
$
337.6

 
$
475.6

 
(29.0
)%
Diesel
424.0

 
417.0

 
1.7
 %
Jet fuel
50.8

 
70.4

 
(27.8
)%
Asphalt, heavy fuel oils and other (3)
179.2

 
210.2

 
(14.7
)%
Total fuel products
$
991.6

 
$
1,173.2

 
(15.5
)%
Total fuel products sales volume (in barrels)
12,776,000

 
19,487,000

 
(34.4
)%
Average fuel products sales price per barrel
$
77.61

 
$
60.20

 
28.9
 %
 
 
 
 
 
 
Total sales
$
1,696.0


$
1,853.5

 
(8.5
)%
Total specialty and fuel products sales volume (in barrels)
17,249,000

 
24,497,000

 
(29.6
)%
 
(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, Superior, San Antonio and Great Falls refineries and crude oil sales from the Superior and San Antonio refineries to third-party customers.
The components of the $24.1 million increase in specialty products segment sales for the six months ended June 30, 2018, as compared to the six months ended June 30, 2017, were as follows:
 
Dollar Change
 
(In millions)
Volume
$
(72.9
)
Sales price
97.0

Total specialty products segment sales increase
$
24.1

Specialty products segment sales increased $24.1 million period over period, or 3.5%, primarily due to an increase in the average selling price per barrel, partially offset by lower sales volume. Sales increased $97.0 million compared to the same period in 2017 due to a $21.69 increase in the average selling price per barrel, driven by an over $16.00 increase in the average cost of

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crude oil per barrel. Average selling prices per barrel increased in all product lines due to market conditions. The decrease in sales volume is due primarily to decreased production at the Shreveport refinery and certain third-party processing facilities as a result of maintenance activities, partially offset by higher sales volume of solvents and packaged and synthetic specialty products due to market conditions.
The components of the $181.6 million decrease in fuel products segment sales for the six months ended June 30, 2018, as compared to the six months ended June 30, 2017, were as follows:
 
Dollar Change
 
(In millions)
Divestiture impact
$
(346.3
)
Volume
(49.8
)
Sales price
214.5

Total fuel products segment sales decrease
$
(181.6
)
Fuel products segment sales decreased $181.6 million period over period, or 15.5%, primarily due to the sale of the Superior Refinery in November 2017 and decreased sales volume, partially offset by an increase in the average selling price per barrel. The average selling price per barrel increased $17.41, or 28.9%, resulting in a $214.5 million increase in sales, driven by an over $14.00 increase in the average cost of crude oil per barrel. The increase in the average selling price per barrel is primarily due to market conditions. Sales volume decreased 34.4% primarily due to the sale of the Superior Refinery in 2017 and decreased production at the Shreveport refinery as a result of maintenance activities.

Gross Profit. Gross profit from continuing operations decreased $36.6 million, or 13.4%, to $236.6 million in the six months ended June 30, 2018, from $273.2 million in the same period in 2017. Gross profit for our specialty and fuel products segments was as follows:
 
Six Months Ended June 30,
 
2018
 
2017
 
% Change
 
(Dollars in millions, except per barrel data)
Gross profit by segment:
 
 
 
 
 
Specialty products:
 
 
 
 
 
Gross profit
$
157.6


$
185.3

 
(14.9
)%
Percentage of sales
22.4
%
 
27.2
%
 


Specialty products gross profit per barrel
$
35.23

 
$
36.99

 
(4.8
)%
Fuel products:
 
 
 
 
 
Gross profit
$
79.0

 
$
87.9

 
(10.1
)%
Percentage of sales
8.0
%
 
7.5
%
 
 
Fuel products gross profit per barrel
$
6.18


$
4.51

 
37.0
 %
Total gross profit
$
236.6

 
$
273.2

 
(13.4
)%
Percentage of sales
14.0
%
 
14.7
%
 
 
The components of the $27.7 million decrease in specialty products segment gross profit for the six months ended June 30, 2018, as compared to the six months ended June 30, 2017, were as follows:
 
Dollar Change
 
(In millions)
Six months ended June 30, 2017 reported gross profit
$
185.3

Cost of materials
(93.9
)
Volume
(30.7
)
Operating costs
(4.1
)
LCM inventory adjustment
4.0

Sales price
97.0

Six months ended June 30, 2018 reported gross profit
$
157.6


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The decrease in specialty products segment gross profit of $27.7 million for the six months ended June 30, 2018, as compared to the same period in 2017, was primarily due to increased cost of materials, decreased sales volume and increased operating costs, partially offset by an increase in the average selling price per barrel and a $4.0 million decrease in the unfavorable LCM inventory. Sales price and cost of materials, net, increased gross profit by $3.1 million, as the average selling price per barrel increased $21.69, while the average cost of crude oil per barrel increased over $16.00. The decrease in sales volume is due primarily to decreased production at the Shreveport refinery and certain third-party processing facilities as a result of maintenance activities, partially offset by higher sales volume of solvents and packaged and synthetic specialty products due to market conditions. The increase in operating costs was primarily due to increased wages and benefits and increased repairs and maintenance, partially offset by a decrease in depreciation and amortization.
The components of the $8.9 million decrease in fuel products segment gross profit for the six months ended June 30, 2018, as compared to the six months ended June 30, 2017, were as follows:
 
Dollar Change
 
(In millions)
Six months ended June 30, 2017 reported gross profit
$
87.9

Cost of materials
(159.4
)
Divestiture impact
(71.2
)
Volume
(8.7
)
Operating costs
(6.5
)
RINs expense
10.7

LCM inventory adjustment
11.7

Sales price
214.5

Six months ended June 30, 2018 reported gross profit
$
79.0

The decrease in fuel products segment gross profit of $8.9 million for the six months ended June 30, 2018, as compared to the same period in 2017, was primarily due to the sale of the Superior Refinery in November 2017, decreased sales volume and increased operating costs, partially offset by widening crack spreads, widening crude oil differentials, decreased RINs expense of $10.7 million, an $11.7 million increase in the favorable LCM inventory adjustment. During the 2018 period, the average cost of crude oil per barrel increased over $14.00, while the average selling price per barrel increased by $17.41. Decreased volume in all product lines was primarily due to the sale of the Superior Refinery in November 2017 as well as a decrease in production at the Shreveport refinery. The $6.5 million increase in operating costs was primarily due to increased wages and benefits, increased repairs and maintenance, partially offset by decreased depreciation and amortization. The decrease in RINs expense primarily resulted from decreased RINs market pricing.
Selling. Selling expenses from continuing operations decreased $6.1 million, or 19.4% to $25.3 million in the six months ended June 30, 2018, from $31.4 million in the same period in 2017. The decrease was primarily due to a $3.3 million decrease in bad debt expense, a $2.4 million decrease in depreciation and amortization, a $1.3 million decrease in advertising expense, a $0.6 million decrease in commissions and decreases related to the sale of the Superior Refinery, partially offset by an increase of $2.0 million in professional fees.
General and administrative. General and administrative expenses from continuing operations increased $9.5 million, or 15.1%, to $72.5 million in the six months ended June 30, 2018, from $63.0 million in the same period in 2017. The increase was primarily due to a $3.9 million increase in depreciation and amortization, a $2.0 million increase in salaries and benefits, a $0.5 million increase in professional fees including ERP costs, a $1.4 million increase in information technology hardware and maintenance expenses and a $0.9 million increase in legal settlements and other increases including utilities and dues and subscriptions, partially offset by decreases related to the sale of the Superior Refinery.
Transportation. Transportation expenses from continuing operations decreased $8.0 million, or 11.2%, to $63.3 million in the six months ended June 30, 2018, from $71.3 million in the same period in 2017. This decrease was due primarily to the sale of the Superior Refinery, decreased freight rates, decreased specialty products sales volumes and the continued optimization of our transportation logistics system.
Other operating (income) expense. Other operating (income) expense from continuing operations increased $19.7 million, or 656.7%, to income of $16.7 million in the six months ended June 30, 2018, from expense of $3.0 million in the same period in 2017. This increase was due primarily to a reduction of the RINs liability associated with the Superior Refinery which was sold in November 2017 as a result of an approval from the EPA of the small refinery exemption from the requirements of the RFS for the 2017 compliance year, decreased RINs market pricing and decreased environmental reserves.

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Interest expense. Interest expense from continuing operations decreased $5.7 million, or 6.4%, to $82.7 million in the six months ended June 30, 2018, from $88.4 million in the same period in 2017, primarily due to the redemption of the 2021 Secured Notes in April 2018 and decreased revolving credit facility borrowings, partially offset by an increase in interest related to the Supply and Offtake Agreements (defined below) and decreased capitalized interest.
Debt extinguishment costs. The Company incurred debt extinguishment costs from continuing operations of $58.8 million during the six months ended June 30, 2018 primarily related to the redemption of the 2021 Secured Notes which were redeemed in April 2018. There was no similar activity during the same period in 2017.
Derivative activity. The following table details the impact of our derivative instruments from continuing operations on the unaudited condensed consolidated statements of operations for the six months ended June 30, 2018 and 2017:
 
Six Months Ended June 30,
 
2018
 
2017
 
(In millions)
Derivative loss reflected in cost of sales
$
(2.1
)
 
$
—

Derivative loss reflected in gross profit
$
(2.1
)
 
$
—

 
 
 
 
Realized loss on derivative instruments
$
(2.1
)

$
(4.9
)
Unrealized gain on derivative instruments
2.8


11.9

Total derivative gain (loss) reflected in the unaudited condensed consolidated statements of operations
$
(1.4
)
 
$
7.0

Total loss on commodity derivative settlements
$
(2.1
)

$
(4.9
)
Gain on derivative instruments. Gain on derivative instruments decreased $6.3 million to $0.7 million in the six months ended June 30, 2018, from $7.0 million in the prior year period. The change was primarily due to a $9.1 million decrease in unrealized gains, partially offset by a $2.8 million decrease in realized losses. The decrease in unrealized gains was primarily due to a $3.1 million decrease in unrealized gains on crude oil and diesel swaps used to economically hedge purchases and sales driven by market conditions, further impacted by an increase in unrealized losses of $6.0 million on embedded derivatives associated with our Supply and Offtake Agreements (defined below). The decrease in realized losses was primarily related to settlements of derivative instruments used to economically hedge crack spreads, crude oil and natural gas.
Net loss from discontinued operations. Net loss from discontinued operations was $2.6 million for six months ended June 30, 2018 compared to $10.1 million in six months ended June 30, 2017. 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 $2.6 million for the six months ended June 30, 2018 relates to a legal reserve and lease terminations. The 2017 discontinued operations represents the operating results and were impacted by increased sales volume driven by an increase in rig count. Increases in crude oil and natural gas prices impacted customers’ drilling and production activities during 2017. 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.

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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 2017 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.
We received over $500 million in cash (excluding any receivables recorded for post-closing adjustments) for the Superior Transaction and the Anchor Transaction combined in 2017. On April 9, 2018, we redeemed all of the 2021 Secured Notes. The holders received a redemption price of 100.0% of the principal amount of the 2021 Secured Notes, plus accrued and unpaid interest thereon up to, but not including, the Redemption Date, plus a Make Whole Premium (as defined in the Indenture, dated April 20, 2016, governing the 2021 Secured Notes). In conjunction with the redemption, we incurred debt extinguishment costs of $58.2 million, including $11.6 million of non-cash charges.
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 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:
 
Six Months Ended June 30,
 
2018
 
2017
 
(In millions)
Net cash used in operating activities
$
(23.3
)
 
$
(35.6
)
Net cash provided by (used in) investing activities
4.8

 
(30.0
)
Net cash provided by (used in) financing activities
(457.0
)
 
88.0

Net increase (decrease) in cash, cash equivalents and restricted cash
$
(475.5
)
 
$
22.4

Operating Activities. Operating activities used cash of $23.3 million during the six months ended June 30, 2018, compared to using cash of $35.6 million during the same period in 2017. The change is primarily due to decreased working capital requirements of $31.2 million, decreased cash used from discontinued operations of $15.5 million, partially offset by decreased net income from continuing operations of $67.6 million. Working capital decreases were primarily driven by the sale of the Superior Refinery in November 2017 and decreased accounts receivable as a result of timing of payments, partially offset by decreased accounts payable as a result of timing of payments, increased inventory due to increased crude oil prices and decreased accrued salaries, wages and benefits as a result of incentive compensation payments.
Investing Activities. Investing activities provided cash of $4.8 million during the six months ended June 30, 2018, compared to using cash of $30.0 million during the prior year period. The change is primarily due to $31.8 million of net cash received as a result of the sale of the Superior Refinery and Anchor and $9.9 million of cash received for the sale of PACNIL, partially offset by payments of $3.8 million for the acquisition of Biosynthetic Technologies and an increase of $3.6 million for capital expenditures.

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Financing Activities. Financing activities used cash of $457.0 million in the six months ended June 30, 2018, compared to providing $88.0 million during the prior year period. This change is primarily due to the payment of $446.6 million in the redemption of the 2021 Secured Notes (including debt extinguishment costs) in 2018, decreased proceeds from the Supply and Offtake Agreements (defined below) of $109.4 million for the period, partially offset by decreased payments on revolving credit facility borrowings of $9.7 million.
Supply and Offtake Agreements
On March 31, 2017, we entered into several agreements with Macquarie Energy North America Trading Inc. (“Macquarie”) to support the operations of our Great Falls refinery (the “Great Falls Supply and Offtake Agreements”). The Great Falls Supply and Offtake Agreements expire on September 30, 2019. On July 27, 2017, we amended the Great Falls Supply and Offtake Agreements to provide Macquarie the option to terminate the Great Falls Supply and Offtake Agreements with nine months’ notice any time prior to June 2019 and we have the option to terminate with ninety days’ notice at any time.
On June 19, 2017, we entered into several agreements with Macquarie to support the operations of the Shreveport refinery (the “Shreveport Supply and Offtake Agreements”, and together with the Great Falls Supply and Offtake Agreements, the “Supply and Offtake Agreements”). The Shreveport Supply and Offtake Agreements expire on June 30, 2020; however, Macquarie has the option to terminate the Shreveport Supply and Offtake Agreements with nine months’ notice any time prior to June 2019 and we have the option to terminate with ninety days’ notice at any time.
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):
 
Six Months Ended June 30,
 
2018

2017
 
(In millions)
Capital improvement expenditures
$
15.1

 
$
11.6

Replacement capital expenditures
5.8

 
6.5

Environmental capital expenditures
5.8

 
4.4

Turnaround capital expenditures
7.6

 
10.3

Total
$
34.3


$
32.8

We estimate our capital expenditures will be between $80 million and $90 million in 2018. 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.
Biosynthetic Technologies
In 2018, we formed Biosyn Holdings, LLC (“Biosyn”) with The Heritage Group (“Heritage Group”), a related party, for the purpose of acquiring Biosynthetic Technologies, a startup company which developed an intellectual property portfolio for the manufacture of renewable-based and biodegradable esters. We incurred approximately $4.0 million in related expenditures. We, through Biosyn, intend to explore a range of alternatives to maximize the value of the acquired intellectual property. This could include internal or external licensing or the sale of the technology for applications across a diverse portfolio of products and solutions in a variety of end-markets. We are designing a commercial scale test at our existing esters manufacturing plant in Missouri.

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Debt and Credit Facilities
As of June 30, 2018, our primary debt and credit instruments consisted of the following:
•
$600.0 million senior secured revolving credit facility maturing in February 2023, subject to borrowing base limitations, with a maximum letter of credit sublimit equal to $300.0 million, which amount may be increased to 90% of revolver commitments in effect with the consent of the Agent (“revolving credit facility”);
•
$900.0 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”).
On April 9, 2018, we redeemed all of the 2021 Secured Notes. The holders received a redemption price of 100.0% of the principal amount of the 2021 Secured Notes, plus accrued and unpaid interest thereon up to, but not including, the Redemption Date, plus a Make Whole Premium (as defined in the Indenture, dated April 20, 2016, governing the 2021 Secured Notes). In conjunction with the redemption, we incurred debt extinguishment costs of $58.2 million, including $11.6 million of non-cash charges.
We were in compliance with all covenants under the debt instruments in place as of June 30, 2018 and believe we have adequate liquidity to conduct our business.
Short Term Liquidity
As of June 30, 2018, our principal sources of short-term liquidity were (i) $342.7 million of availability under our revolving credit facility, (ii) inventory financing agreements related to the Great Falls and Shreveport refineries and (iii) $38.8 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 a $600.0 million amended and restated senior secured revolving credit facility maturing in February 2023, subject to borrowing base limitations, with a maximum letter of credit sublimit equal to $300.0 million.
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 June 30, 2018, we had availability on our revolving credit facility of approximately $342.7 million, based on a borrowing base of approximately $373.6 million, $30.8 million in outstanding standby letters of credit and approximately $0.1 million in 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, payments of quarterly distributions to unitholders, 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 June 30, 2018, the maximum revolving credit facility borrowing was $43.0 million. 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 June 30, 2018, availability for additional borrowings under our revolving credit facility was approximately $262.1 million at its lowest point.
The revolving credit facility currently bears interest at a rate equal to prime plus a basis points margin or LIBOR plus a basis points margin, at our option which 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. As of June 30, 2018, this margin was 50 basis points for prime, 150 basis points for LIBOR, 150 basis points for prime rate based FILO loans and 250 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.
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

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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 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 and (ii) $60 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 Borrowing Base (as defined in the revolving credit facility agreement) and (ii) $35 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 June 30, 2018, we had $900.0 million in 2021 Notes, $350.0 million in 2022 Notes and $325.0 million in 2023 Notes outstanding. As of December 31, 2017, we had $400.0 million in 2021 Secured Notes, $900.0 million in 2021 Notes, $350.0 million in 2022 Notes and $325.0 million in 2023 Notes outstanding. For more information regarding the redemption of our 2021 Secured 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.
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 June 30, 2018, our Fixed Charge Coverage Ratio (as defined in the indentures governing the 2021, 2022 and 2023 Notes) was 1.6 to 1.0.
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.

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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 2017 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 June 30, 2018. 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.
Contractual Obligations and Commercial Commitments
A summary of our total contractual cash obligations as of June 30, 2018, at current maturities and reflecting only those line items that have materially changed since December 31, 2017, 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)
$
491.2


$
119.4


$
237.3


$
92.0


$
42.5

Operating lease obligations (2)
90.0


29.4


35.9


15.3


9.4

Letters of credit (3)
30.8


30.8


—


—


—

Purchase commitments (4)
544.1


332.8


95.7


42.0


73.6

Employment agreements (5)
1.7

 
0.9

 
0.8

 
—

 
—

Financing activities:









Obligations under inventory financing agreements
109.7

 
109.7

 
—

 
—

 
—

Capital lease obligations
42.2


1.5


2.0


2.4


36.3

Long-term debt obligations, excluding capital lease obligations
1,581.0


1.4


903.1


676.5


—

Total obligations
$
2,890.7


$
625.9


$
1,274.8


$
828.2


$
161.8

 
(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 capital 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 July 2055.
(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.

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(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.
We have a feedstock purchase agreement with Phillips 66 related to the LVT unit at its Lake Charles, Louisiana refinery (the “LVT Feedstock Agreement”). Pursuant to the LVT Feedstock Agreement, Phillips 66 is obligated to supply a minimum quantity of feedstock for the LVT unit effective through December 31, 2020. Based upon the minimum supply quantity, we expect to purchase $128.2 million of feedstock for the LVT unit in the term of the agreement extension based on pricing estimates as of June 30, 2018. This amount is not included in the table above.
For additional information regarding our expected capital and turnaround expenditures for the remainder of 2018, 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 or operating lease transactions during the three and six months ended June 30, 2018.
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 2017 Annual Report. There have been no material changes to such policies that occurred during the quarterly period ended June 30, 2018.
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.”
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 2017 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 (“LLS”), WCS, WTI Midland, Mixed Sweet Blend (“MSW”) and ICE Brent.

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We have entered into WCS crude oil basis swaps to mitigate the risk of future changes in pricing differentials between WCS and NYMEX WTI. The following table provides a summary of the WCS crude oil basis swaps as of June 30, 2018 in our fuel products segment:
WCS Crude Oil Basis Swap Contracts by Expiration Dates
Barrels Purchased
 
BPD
 
Average Swap
($/Bbl)
Third Quarter 2018
184,000

 
2,000

 
$
24.98

Fourth Quarter 2018
184,184

 
2,002

 
$
26.13

First Quarter 2019
90,000

 
1,000

 
$
22.20

Second Quarter 2019
91,000

 
1,000

 
$
22.20

Third Quarter 2019
92,000

 
1,000

 
$
22.20

Fourth Quarter 2019
92,000

 
1,000

 
$
22.20

Total
733,184

 
 
 
 
Average price


 


 
$
23.32

We have entered into WCS crude oil percentage basis swaps to secure a percentage differential on WCS crude oil to NYMEX WTI. The following table provides a summary of crude oil percentage basis swap contracts related to crude oil purchases as of June 30, 2018 in our fuel products segment:
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

 
66.68
%
Second Quarter 2019
455,000

 
5,000

 
66.68
%
Third Quarter 2019
460,000

 
5,000

 
66.68
%
Fourth Quarter 2019
460,000

 
5,000

 
66.68
%
Total
1,825,000

 
 
 
 
Average percentage
 
 
 
 
66.68
%
We have entered into WTI Midland crude oil basis swaps to mitigate the risk of future changes in pricing differentials between WTI Midland and NYMEX WTI. The following table provides a summary of the Midland crude oil basis swaps as of June 30, 2018 in our fuel products segment:
Midland Crude Oil Basis Swap Contracts by Expiration Dates
Barrels Purchased
 
BPD
 
Average Swap
($/Bbl)
Third Quarter 2018
782,000

 
8,500

 
$
11.39

Fourth Quarter 2018
874,000

 
9,500

 
$
15.13

First Quarter 2019
765,000

 
8,500

 
$
13.01

Second Quarter 2019
773,500

 
8,500

 
$
11.88

Total
3,194,500

 
 
 
 
Average price
 
 
 
 
$
12.85

We have entered into derivative instruments related to diesel crack spread sales. The following table provides a summary of diesel crack spread swaps as of June 30, 2018 in our fuel products segment:
Diesel Crack Spread Swap Contracts by Expiration Dates
Barrels Sold
 
BPD
 
Average Swap
($/Bbl)
Third Quarter 2018
184,000

 
2,000

 
$
24.30

Fourth Quarter 2018
184,000

 
2,000

 
$
24.75

First Quarter 2019
90,000

 
1,000

 
$
26.80

Second Quarter 2019
91,000

 
1,000

 
$
26.80

Third Quarter 2019
92,000

 
1,000

 
$
26.80

Fourth Quarter 2019
92,000

 
1,000

 
$
26.80

Total
733,000

 
 
 
 
Average price
 
 
 
 
$
26.04


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We have entered into 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. The following table provides a summary of the diesel percent basis crack spread swaps as of June 30, 2018 in our fuel products segment:
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

 
138.75
%
Second Quarter 2019
455,000

 
5,000

 
138.75
%
Third Quarter 2019
460,000

 
5,000

 
138.75
%
Fourth Quarter 2019
460,000

 
5,000

 
138.75
%
Total
1,825,000

 
 
 
 
Average percentage
 
 
 
 
138.75
%
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 and a further discussion of our hedging policies.
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 constant (RINs requirements), a $1.00 increase in the price of RINs as of June 30, 2018, would be expected to have a negative impact on net loss for 2018 of approximately $14.6 million.
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 June 30, 2018 and December 31, 2017, 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.”
 
June 30, 2018
 
December 31, 2017
 
Fair Value
 
Carrying Value
 
Fair Value
 
Carrying Value
 
(In millions)
Financial Instrument:
 
 
 
 
 
 
 
2021 Secured Notes
$
—

 
$
—

 
$
456.4

 
$
387.6

2021 Notes
$
896.0

 
$
893.6

 
$
896.4

 
$
892.5

2022 Notes
$
351.0

 
$
345.3

 
$
352.4

 
$
344.8

2023 Notes
$
326.0

 
$
319.6

 
$
327.7

 
$
319.1

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 June 30, 2018, 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 approximately $0.1 million outstanding variable rate debt as of June 30, 2018 and $0.2 million as of December 31, 2017.

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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 June 30, 2018, at the reasonable assurance level due to material weaknesses in our internal control over financial reporting as described below.
On September 1, 2017, we implemented an enterprise resource planning (“ERP”) system on a company-wide basis, which is expected to improve the efficiency of certain financial and related transaction processes. The implementation resulted in business and operational interruptions and the three material weaknesses identified below. The material weaknesses are as follows:
•The ineffective design and implementation of effective controls with respect to the implementation of our ERP system consistent with our financial reporting requirements.  Specifically, management did not exercise sufficient corporate governance and oversight, 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 ineffective design and maintenance of information technology (“IT”) general controls for the ERP system that are relevant to the preparation of our financial statements. Specifically, we did not (i) maintain adequate user access controls to ensure appropriate segregation of duties and to adequately restrict access to financial applications and data; and (ii) maintain program change management controls to ensure that IT program and data changes affecting financial IT applications and underlying accounting records were tested, approved and implemented appropriately.
•The untimely and insufficient operation of controls in the financial statement close process, specifically 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 impacting all financial statement accounts and disclosures.
Planned Remediation Efforts to Address Material Weaknesses
In order to remediate these material weaknesses and further strengthen the overall controls surrounding information systems, we are taking the following steps to improve the overall processes and controls:
•Corporate Governance and Oversight - We hired a new Chief Accounting Officer in September 2017 who has significant SAP and ERP implementation experience to help enhance the capabilities of existing management to oversee the ongoing work being completed to help stabilize the ERP system and oversee the key enhancements needed to enable us to realize the value of the system. In addition, we re-organized the IT organization and are further enhancing the accounting organization to better equip the teams to manage the changes resulting from the ERP system.
•Data Integrity and Data Conversion - We have implemented additional controls around data management and review of changes.
•End User Training - To reinforce the importance of our control environment across the company, we are developing and providing additional training to employees to enhance their understanding of the new ERP system so that they can effectively operate the system.
•User Access IT General Controls - We are addressing segregation of duties conflicts in addition to developing controls so that appropriate system access rights are granted to system users and controls related to routine reviews of user system access. In addition, we have implemented a new delegation of authority policy.
•Program Change IT General Controls - We are developing a more robust process for the initiation, testing and approval of change activities.
•Financial Statement Close Process - We are reviewing, analyzing, and properly documenting our processes related to internal controls over financial reporting. In addition, we are designing and implementing additional review and approval controls over account reconciliations, journal entries, and management estimates across our internal control processes. These controls will address the accuracy and completeness of the data used in the performance of the respective control.

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We began the remediation process outlined above prior to September 30, 2017 and are progressing on our plans to remediate the material weaknesses noted above. When fully implemented and operational, we believe the steps described above will remediate the control deficiencies that have led to the material weaknesses and strengthen our internal controls over financial reporting. Management is committed to improving our internal control processes. As we continue to evaluate and work to improve our internal controls over financial reporting, we may determine to take additional measures to address control deficiencies or modify certain activities of the remediation measures described above.
(b) Changes in Internal Control over Financial Reporting
We are taking actions to remediate the material weaknesses relating to our internal controls over financial reporting, as described above. Except as otherwise described herein, there were no changes in our internal control over financial reporting that occurred 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 2017 Annual Report. 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 2017 Annual Report.
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
None.
Item 6. Exhibits
See Index to Exhibits of this Quarterly Report.


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Index to Exhibits
Exhibit
Number
 
Description
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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:
August 9, 2018
By:
/s/ Christopher H. Bohnert
 
 
 
Christopher H. Bohnert
 
 
 
Chief Accounting Officer
 
 
 
(Authorized Person and Principal Accounting Officer)
 
 
 
 

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