Document
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, 2017
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 7, 2017, there were 76,729,706 common units outstanding.
 

Table of Contents

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
QUARTERLY REPORT
For the Three and Six Months Ended June 30, 2017
Table of Contents
 
 
Page
 

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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 expectations regarding annual EBITDA contributions from our multi-year, self-help program, (iii) 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, (iv) 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”), (v) our ability to meet our financial commitments, minimum quarterly distributions to our unitholders, debt service obligations, debt instrument covenants, contingencies and anticipated capital expenditures and (vi) 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, 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 current expectations and beliefs 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, 2016 (“2016 Annual Report”), (ii) Part II, Item 1A “Risk Factors” in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2017 (“Q1 Quarterly Report”) and (iii) Part I, Item 3 “Quantitative and Qualitative Disclosures About Market Risk” and Part II, Item 1A “Risk Factors” in this Quarterly Report. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.
References in this Quarterly Report to “Calumet Specialty Products Partners, L.P.,” “Calumet,” “the Company,” “we,” “our,” “us” or like terms refer to Calumet Specialty Products Partners, L.P. and its subsidiaries. References in this Quarterly Report to “our general partner” refer to Calumet GP, LLC, the general partner of Calumet Specialty Products Partners, L.P.




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PART I
Item 1. Financial Statements
CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
CONDENSED CONSOLIDATED BALANCE SHEETS

 
June 30, 2017
 
December 31, 2016
 
(Unaudited)
 
 
 
(In millions, except unit data)
ASSETS
Current assets:
 
 
 
Cash and cash equivalents
$
26.6

 
$
4.2

Accounts receivable:
 
 
 
Trade
277.5

 
216.4

Other
11.8

 
22.3

 
289.3

 
238.7

Inventories
438.5

 
386.2

Derivative assets
1.0

 
0.8

Prepaid expenses and other current assets
13.9

 
11.0

Total current assets
769.3

 
640.9

Property, plant and equipment, net
1,633.2

 
1,678.0

Investment in unconsolidated affiliates
10.1

 
10.3

Goodwill
177.2

 
177.2

Other intangible assets, net
162.1

 
178.5

Other noncurrent assets, net
36.6

 
40.3

Total assets
$
2,788.5

 
$
2,725.2

LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
 
 
 
Accounts payable
$
312.2

 
$
295.5

Accrued interest payable
52.4

 
52.5

Accrued salaries, wages and benefits
22.8

 
11.5

Other taxes payable
21.4

 
20.8

Obligations under inventory financing agreements
103.5

 
—

Other current liabilities
46.2

 
99.6

Current portion of long-term debt
3.4

 
3.5

Derivative liabilities
2.1

 
14.8

Total current liabilities
564.0

 
498.2

Deferred income taxes
2.3

 
2.3

Pension and postretirement benefit obligations
10.9

 
11.3

Other long-term liabilities
0.9

 
1.0

Long-term debt, less current portion
1,986.4

 
1,993.7

Total liabilities
2,564.5

 
2,506.5

Commitments and contingencies
 
 
 
Partners’ capital:
 
 
 
Limited partners’ interest 76,729,706 units and 76,392,258 units, issued and outstanding as of June 30, 2017 and December 31, 2016, respectively
216.3

 
211.2

General partner’s interest
16.0

 
15.8

Accumulated other comprehensive loss
(8.3
)
 
(8.3
)
Total partners’ capital
224.0

 
218.7

Total liabilities and partners’ capital
$
2,788.5

 
$
2,725.2

See accompanying notes to unaudited condensed consolidated financial statements.

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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2017
 
2016
 
2017
 
2016
 
(In millions, except per unit and unit data)
Sales
$
1,030.9

 
$
972.9

 
$
1,968.3

 
$
1,685.9

Cost of sales
870.5

 
841.6

 
1,668.4

 
1,468.4

Gross profit
160.4

 
131.3

 
299.9

 
217.5

Operating costs and expenses:
 
 
 
 
 
 
 
Selling
28.2

 
26.2

 
55.7

 
56.7

General and administrative
33.6

 
24.8

 
65.4

 
52.4

Transportation
41.1

 
45.0

 
81.7

 
84.2

Taxes other than income taxes
4.9

 
4.2

 
10.4

 
9.9

Asset impairment
—

 
33.4

 
0.4

 
33.4

Other
1.1

 
0.3

 
3.0

 
2.3

Operating income (loss)
51.5

 
(2.6
)
 
83.3

 
(21.4
)
Other income (expense):
 
 
 
 
 
 
 
Interest expense
(44.5
)
 
(42.8
)
 
(88.4
)
 
(73.1
)
Gain on derivative instruments
1.3

 
17.8

 
7.0

 
10.1

Loss from unconsolidated affiliates
(0.1
)
 
(7.1
)
 
(0.2
)
 
(18.2
)
Loss from sale of unconsolidated affiliates
—


(113.4
)

—


(113.4
)
Other
0.5

 
0.5

 
0.7

 
0.9

Total other expense
(42.8
)
 
(145.0
)
 
(80.9
)
 
(193.7
)
Net income (loss) before income taxes
8.7

 
(147.6
)
 
2.4

 
(215.1
)
Income tax expense (benefit)
(0.9
)
 
0.3

 
(1.0
)
 
0.5

Net income (loss)
$
9.6

 
$
(147.9
)
 
$
3.4

 
$
(215.6
)
Allocation of net income (loss):
 
 
 
 
 
 
 
Net income (loss)
$
9.6

 
$
(147.9
)
 
$
3.4

 
$
(215.6
)
Less:
 
 
 
 
 
 
 
General partner’s interest in net income (loss)
0.2

 
(2.9
)
 
0.1

 
(4.3
)
Non-vested share based payments
0.2

 
—

 
0.2

 
—

Net income (loss) available to limited partners
$
9.2

 
$
(145.0
)
 
$
3.1

 
$
(211.3
)
Weighted average limited partner units outstanding:
 
 
 
 
 
 
 
Basic
77,554,815

 
76,761,504

 
77,485,058

 
76,491,775

Diluted
77,714,112

 
76,761,504

 
77,725,656

 
76,491,775

Limited partners’ interest basic and diluted net income (loss) per unit
$
0.12

 
$
(1.89
)
 
$
0.04

 
$
(2.76
)
Cash distributions declared per limited partner unit
$
—

 
$
—

 
$
—

 
$
0.685

See accompanying notes to unaudited condensed consolidated financial statements.


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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2017
 
2016
 
2017
 
2016
 
(In millions)
Net income (loss)
$
9.6

 
$
(147.9
)
 
$
3.4

 
$
(215.6
)
Other comprehensive (income) loss:
 
 
 
 
 
 
 
Cash flow hedges:
 
 
 
 
 
 
 
Cash flow hedge gain reclassified to net income (loss)
—

 
(2.3
)
 
—

 
(4.4
)
Defined benefit pension and retiree health benefit plans
—

 
0.1

 
—

 
0.1

Total other comprehensive loss
—

 
(2.2
)
 
—

 
(4.3
)
Comprehensive income (loss) attributable to partners’ capital
$
9.6

 
$
(150.1
)
 
$
3.4

 
$
(219.9
)
See accompanying notes to unaudited condensed consolidated financial statements.


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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
 
 
Accumulated Other
Comprehensive Loss
 
Partners’ Capital
 
 
 
 
General
Partner
 
Limited
Partners
 
Total
 
(In millions)
Balance at December 31, 2016
$
(8.3
)
 
$
15.8

 
$
211.2

 
$
218.7

Net income
—

 
0.1

 
3.3

 
3.4

Amortization of phantom units
—

 
—

 
2.2

 
2.2

Settlement of tax withholdings on equity-based incentive compensation
—

 
—

 
(0.4
)
 
(0.4
)
Contributions from Calumet GP, LLC
—

 
0.1

 
—

 
0.1

Balance at June 30, 2017
$
(8.3
)
 
$
16.0

 
$
216.3

 
$
224.0

See accompanying notes to unaudited condensed consolidated financial statements.

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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
 
Six Months Ended June 30,
 
2017

2016
 
(In millions)
Operating activities
 
 
 
Net income (loss)
$
3.4


$
(215.6
)
Adjustments to reconcile net income (loss) to net cash used in operating activities:
 
 
 
Depreciation and amortization
82.0


82.6

Amortization of turnaround costs
14.0


17.4

Non-cash interest expense
4.8


4.6

Provision for doubtful accounts
0.1


0.5

Unrealized gain on derivative instruments
(11.9
)

(28.4
)
Asset impairment
0.4

 
33.4

(Gain) loss on disposal of fixed assets
1.5

 
(0.7
)
Non-cash equity based compensation
3.3


2.9

Deferred income tax expense (benefit)
0.1

 
(0.2
)
Lower of cost or market inventory adjustment
(8.0
)
 
(44.4
)
Loss from unconsolidated affiliates
0.2

 
18.2

Loss on sale of unconsolidated affiliates
—

 
113.4

Other non-cash activities
3.3


2.3

Changes in assets and liabilities:
 
 
 
Accounts receivable
(50.7
)

(60.0
)
Inventories
(44.3
)

(10.3
)
Prepaid expenses and other current assets
(2.1
)

(1.5
)
Derivative activity
(0.3
)

(10.4
)
Turnaround costs
(10.3
)

(8.1
)
Other assets
—

 
(0.4
)
Accounts payable
24.2


35.1

Accrued interest payable
(0.1
)

9.1

Accrued salaries, wages and benefits
10.2


(16.0
)
Other taxes payable
0.6


3.2

Other liabilities
(55.6
)

22.5

Pension and postretirement benefit obligations
(0.4
)

(0.9
)
Net cash used in operating activities
(35.6
)
 
(51.7
)
Investing activities
 
 
 
Additions to property, plant and equipment
(30.0
)

(87.9
)
Investment in unconsolidated affiliates
—


(41.8
)
Proceeds from sale of unconsolidated affiliates
—

 
29.0

Proceeds from sale of property, plant and equipment
—

 
1.9

Net cash used in investing activities
(30.0
)
 
(98.8
)
Financing activities
 
 
 
Proceeds from borrowings — revolving credit facility
606.9

 
479.0

Repayments of borrowings — revolving credit facility
(616.7
)
 
(589.9
)
Proceeds from borrowings — senior notes
—

 
393.1

Repayments of borrowings — related party note
—

 
(34.5
)
Payments on capital lease obligations
(4.5
)
 
(4.1
)
Proceeds from inventory financing agreements
105.4

 
—

Other financing activities
(0.7
)
 
2.4

Debt issuance costs
(2.1
)
 
(9.9
)
Contributions from Calumet GP, LLC
0.1

 
0.2

Taxes paid for phantom unit grants
(0.4
)
 
(1.8
)
Distributions to partners
—

 
(57.4
)
Net cash provided by financing activities
88.0

 
177.1

Net increase in cash and cash equivalents
22.4

 
26.6

Cash and cash equivalents at beginning of period
4.2


5.6

Cash and cash equivalents at end of period
$
26.6

 
$
32.2

Supplemental disclosure of non-cash financing and investing activities
 
 
 
Non-cash property, plant and equipment additions
$
6.5

 
$
20.5

See accompanying notes to unaudited condensed consolidated financial statements.

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CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
1. Description of the Business
Calumet Specialty Products Partners, L.P. (the “Company”) is a publicly traded Delaware limited partnership listed on the NASDAQ Global Select Market (“NASDAQ”) under the ticker symbol “CLMT.” The general partner of the Company is Calumet GP, LLC, a Delaware limited liability company. As of June 30, 2017, the Company had 76,729,706 limited partner common units and 1,565,912 general partner equivalent units outstanding. The general partner owns 2% of the Company and all of the incentive distribution rights (as defined in the Company’s partnership agreement), while the remaining 98% is owned by limited partners. The general partner employs all of the Company’s employees and the Company reimburses the general partner for certain of its expenses.
The Company is engaged in the production and marketing of crude oil-based specialty products including lubricating oils, white mineral oils, solvents, petrolatums and waxes and fuel and fuel related products including gasoline, diesel, jet fuel, asphalt and heavy fuel oils, in addition to oilfield services and products. The Company owns and leases additional facilities, primarily related to production and distribution of specialty, fuel and oilfield services products, throughout the United States (“U.S.”).
The unaudited condensed consolidated financial statements of the Company as of June 30, 2017, and for the three and six months ended June 30, 2017 and 2016, included herein have been prepared, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). Certain information and disclosures normally included in the consolidated financial statements prepared in accordance with generally accepted accounting principles (“GAAP”) in the U.S. have been condensed or omitted pursuant to such rules and regulations, although the Company believes that the following disclosures are adequate to make the information presented not misleading. The preparation of the unaudited condensed consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the unaudited condensed consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. These unaudited condensed consolidated financial statements reflect all adjustments that, in the opinion of management, are necessary to present fairly the results of operations for the interim periods presented. All adjustments are of a normal nature, unless otherwise disclosed. The results of operations for the three and six months ended June 30, 2017 are not necessarily indicative of the results that may be expected for the year ending December 31, 2017. These unaudited condensed consolidated financial statements should be read in conjunction with the Company’s 2016 Annual Report.
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 as of June 30, 2017 and December 31, 2016 (in millions):
 
June 30, 2017
 
December 31, 2016
RINs Obligation
$
25.6

 
$
79.3

Other
20.6

 
20.3

Total
$
46.2

 
$
99.6

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

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The Company uses the inventory model to account for RINs, measuring acquired RINs at weighted-average cost. The cost of RINs used each period is charged to cost of sales with cash inflows and outflows recorded in the operating cash flow section of the unaudited condensed consolidated statements of cash flows. The liability is calculated by multiplying the RINs shortage (based on actual results) by the period end RIN spot price. The Company recognizes an asset at the end of each reporting period in which it has generated RINs in excess of its RINs Obligation. The asset is calculated by multiplying the RINs surplus (based on actual results) by the period end RIN spot price. The value of RINs in excess of the RINs Obligation, if any, would be reflected in other current assets on the condensed consolidated balance sheets. RINs generated in excess of the Company’s current RINs Obligation may be sold or held to offset future RINs Obligations. Any such sales of excess RINs are recorded in cost of sales in the unaudited condensed consolidated statements of operations. The assets and liabilities associated with our RINs Obligation are considered recurring fair value measurements. See Note 5 for further information on the Company’s RINs Obligation.
New Accounting Pronouncements
In May 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2017-09, Compensation - Stock Compensation (Topic 718) - Scope of Modification Accounting (“ASU 2017-09”). ASU 2017-09 amends prior guidance by further defining when a change to the terms of a share-based award are required to be accounted for as a modification under the rules by providing specific criteria. ASU 2017-09 is effective for annual periods beginning after December 15, 2017. The adoption of ASU 2017-09 is not expected to have an impact on the Company’s unaudited condensed consolidated financial statements.
In March 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost (“ASU 2017-07”). The changes to the standard require employers to report the service cost component in the same line item as other compensation costs arising from services rendered by employees during the reporting period. The other components of net benefit costs will be presented in the statement of operations separately from the service cost and outside of a subtotal of operating income (loss). In addition, only the service cost component may be eligible for capitalization where applicable. ASU 2017-07 is effective for annual periods beginning after December 15, 2017. The adoption of ASU 2017-07 is not expected to have an impact on the Company’s unaudited condensed consolidated financial statements.
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which supersedes the lease accounting requirements in Accounting Standards Codification (“ASC”) Topic 840, Leases. ASU 2016-02 provides principles for the recognition, measurement, presentation and disclosure of leases for both lessees and lessors. The new standard requires lessees to apply a dual approach, classifying leases as either finance or operating leases based on the principle of whether or not the lease is effectively a financed purchase by the lessee. This classification will determine whether lease expense is recognized based on an effective interest method or on a straight-line basis over the term of the lease, respectively. A lessee is also required to record a right-of-use asset and a lease liability for all leases with a term of greater than twelve months regardless of classification. Leases with a term of twelve months or less will be accounted for similar to existing guidance for operating leases. The amendments in this standard are effective for fiscal years (including interim periods) beginning after December 15, 2018, with early adoption permitted and modified retrospective application required. The Company is currently evaluating the impact of this standard on its consolidated financial statements.
In January 2016, the FASB issued ASU No. 2016-01, Financial Instruments — Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities (“ASU 2016-01”). ASU 2016-01 requires that (i) equity investments in unconsolidated entities that are not accounted for under the equity method of accounting generally be measured at fair value with changes recognized in net income (loss) and (ii) when the fair value option has been elected for financial liabilities, changes in fair value due to instrument-specific credit risk be recognized separately in other comprehensive income (loss). Additionally, ASU 2016-01 changes the presentation and disclosure requirements for financial instruments. The amendments in this standard are generally effective for fiscal years (including interim periods) beginning after December 15, 2017, with early adoption not permitted. The adoption of ASU 2016-01 is not expected to have an impact on the Company’s unaudited condensed consolidated financial statements.
In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”), which supersedes the revenue recognition requirements in Accounting Standard Codification Topic 605, Revenue Recognition. ASU 2014-09 is based on the principle that revenue is recognized to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This ASU also requires enhanced disclosures. In August 2015, the FASB issued ASU No. 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date, which defers the original effective date by one year to annual and interim periods beginning after December 15, 2017, with early adoption permitted as of the original effective date. ASU 2014-09 allows for either a full retrospective or a modified retrospective transition method. In March, April, May and December 2016, the FASB clarified the implementation guidance on principal versus agent considerations, identifying performance obligations, licensing, collectibility, presentation of sales taxes, non-cash consideration, transition, the scope of Topic 606, impairment testing, policy elections over determining the provision for losses on certain types of contracts, the accrual of advertising costs and disclosure requirements.

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All amendments are effective with the same date as ASU 2014-09. The Company is currently evaluating the impact of these standards on its unaudited condensed consolidated financial statements. The Company is required to adopt ASU 2014-09 as of January 1, 2018, expects to use the modified retrospective approach and is in the process of evaluating the full impact of adoption on the Company’s financial reporting. The Company has an implementation work team evaluating contracts from the various revenue streams across all of its business segments to evaluate and implement changes to business processes, systems and controls.
Based on the evaluation performed to date, the Company has identified some contracts within the oilfield services segment that include implicit arrangements that could be considered material rights under the new standard. Additionally, these contracts contain elements of variable consideration that may impact the total transaction price for these contracts. The Company does not believe that these elements would result in a material change to how revenue would be recognized for these contracts upon the adoption of ASU 2014-09.
Based on the evaluation performed to date, the Company has identified some agreements with distributors within the specialty products segment that are subject to rebate and incentive programs that could contain elements of material rights and/or variable consideration. The Company does not believe that these elements would result in a material change to how revenue would be recognized for these agreements upon the adoption of ASU 2014-09.
The Company continues to analyze the full impact on its operating segments of the adoption of ASU 2014-09, which may result in differences between current revenue recognition practices and those required by ASU 2014-09 that may be material. As part of the Company’s evaluation, it has segregated its revenue streams into categories which will serve as the basis for the continuing accounting analysis on, and documentation of revenues, as it relates to the impact of ASU 2014-09. In addition, the Company continues to actively monitor outstanding issues currently being addressed by the American Institute of Certified Public Accountants’ Revenue Recognition Working Group and the FASB’s Transition Resource Group, since conclusions reached by these groups may impact its application of ASU 2014-09.
3. 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 $34.4 million and $14.4 million lower as of June 30, 2017, and December 31, 2016, respectively.
On March 31, 2017 and June 19, 2017, the Company sold inventory comprised of crude oil and refined products to Macquarie Energy North America Trading Inc. (“Macquarie”) under Supply and Offtake Agreements as described in Note 6 — “Inventory Financing Agreements” related to the Great Falls and Shreveport refineries, respectively. The crude oil remains in the legal title of Macquarie and is stored in the Company’s refinery storage tanks governed by storage agreements. Legal title to the crude oil passes to the Company at the storage tank outlet. After processing, Macquarie takes title to the refined products stored in the Company’s storage tanks until sold to third parties. The Company records the inventory owned by Macquarie on the Company’s behalf as inventory with a corresponding obligation on the Company’s condensed consolidated balance sheets because Macquarie maintains the risk of loss until the refined products are sold to third parties and the Company is obligated to repurchase the inventory in certain scenarios. The agreements are accounted for similar to a product financing arrangement.
Inventories consist of the following (in millions):
 
June 30, 2017
 
December 31, 2016
 
Titled
Inventory
 
Supply and Offtake
Agreements (1)
 
Total
 
Titled
Inventory
 
Supply and Offtake
Agreements (1)
 
Total
Raw materials
$
49.0

 
$
15.0

 
$
64.0

 
$
57.4

 
$
—

 
$
57.4

Work in process
49.0

 
24.5

 
73.5

 
74.2

 
—

 
74.2

Finished goods
244.1

 
56.9

 
301.0

 
254.6

 
—

 
254.6

 
$
342.1

 
$
96.4

 
$
438.5

 
$
386.2

 
$
—

 
$
386.2

 
(1) Amounts represent LIFO value and do not necessarily represent the value at which the inventory was sold. Refer to Note 6 for further information.
Under the LIFO method, the most recently incurred costs are charged to cost of sales and inventories are valued at the earliest acquisition costs. In addition, the use of the LIFO inventory method may result in increases or decreases to cost of sales in years

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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, 2017 and 2016, the Company recorded decreases of $4.0 million and $36.3 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, 2017 and 2016, the Company recorded decreases of $8.0 million and $44.4 million, respectively, in cost of sales in the unaudited condensed consolidated statements of operations due to the LCM valuation.
4. Investment In Unconsolidated Affiliates
The following table summarizes the Company’s investments in unconsolidated affiliates as of June 30, 2017, and December 31, 2016 (in millions):
 
June 30, 2017
 
December 31, 2016
 
Investment
 
Percent Ownership
 
Investment
 
Percent Ownership
Pacific New Investment Limited
$
9.6

 
23.8
%
 
$
9.6

 
23.8
%
Other
0.5

 
 
 
0.7

 
 
Total
$
10.1

 
 
 
$
10.3

 
 
Pacific New Investment Limited and Shandong Hi-Speed Hainan Development Co., Ltd.
On August 5, 2015, the Company and The Heritage Group, a related party, formed Pacific New Investment Limited (“PACNIL”) for the purpose of investing in a joint venture with Shandong Hi-Speed Materials Group Corporation and China Construction Installation Engineering Co., Ltd. to construct, develop and operate a solvents refinery in mainland China. The joint venture is named Shandong Hi-Speed Hainan Development Co., Ltd. (“Hi-Speed”). The Company invested $4.8 million in June 2016 and $4.8 million in October 2016. As of June 30, 2017 and December 31, 2016, the Company owned an equity interest of approximately 23.8% in PACNIL, and through that ownership the Company owned an equity interest of approximately 6.0% in Hi-Speed. PACNIL wishes to exit its investment in Hi-Speed. The Company and PACNIL believe they will fully recover their investment in the Hi-Speed joint venture.
The Company accounts for its ownership in PACNIL under the equity method of accounting. As of June 30, 2017 and December 31, 2016, the Company had an investment of $9.6 million in PACNIL, primarily related to the purchase of equity in the Hi-Speed joint venture.
Dakota Prairie Refining, LLC
On June 27, 2016, the Company consummated the sale of its 50% equity interest in Dakota Prairie Refining, LLC (“Dakota Prairie”) to joint venture partner WBI Energy, Inc. (“WBI”), a wholly owned subsidiary of MDU Resources Group, Inc. (“MDU”). Concurrent with the Company’s sale of its equity interest in Dakota Prairie to WBI, Tesoro Refining & Marketing Company LLC (“Tesoro”) acquired 100% of Dakota Prairie from WBI in a separate transaction that closed on June 27, 2016.
Under the terms of the definitive agreement with WBI, the Company received consideration of $28.5 million, which was offset by the Company’s repayment of $36.0 million in borrowings under Dakota Prairie’s revolving credit facility. In addition, the Company’s $39.4 million letter of credit supporting the Dakota Prairie revolving credit facility was terminated. As part of the transaction, MDU and WBI released the Company from all liabilities arising out of or related to Dakota Prairie. In addition, Tesoro and Dakota Prairie released the Company from all liabilities arising out of the organization, management and operation of Dakota Prairie, subject to certain limited exceptions. Further, WBI agreed to indemnify the Company from all liabilities arising out of or related to Dakota Prairie, subject to certain limited exceptions. As a result of the sale of Dakota Prairie, the Company recorded a loss on sale of unconsolidated affiliate of $113.9 million during the six months ended June 30, 2016.
5. Commitments and Contingencies
From time to time, the Company is a party to certain claims and litigation incidental to its business, including claims made by various regulatory and taxation authorities, such as the EPA, various state environmental regulatory bodies, the Internal Revenue Service, various state and local departments of revenue and the federal Occupational Safety and Health Administration (“OSHA”), as the result of audits or reviews of the Company’s business. In addition, the Company has property, business interruption, general liability and various other insurance policies that may result in certain losses or expenditures being reimbursed to the Company.
Environmental
The Company conducts crude oil and specialty hydrocarbon refining, blending and terminal operations in addition to providing oilfield services and products, and such activities are subject to stringent federal, state, regional and local laws and regulations

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governing worker health and safety, the discharge of materials into the environment and environmental protection. These laws and regulations impose obligations that are applicable to the Company’s operations, such as requiring the acquisition of permits to conduct regulated activities, restricting the manner in which the Company may release materials into the environment, requiring remedial activities or capital expenditures to mitigate pollution from former or current operations, requiring the application of specific health and safety criteria addressing worker protection and imposing substantial liabilities for pollution resulting from its operations. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil and criminal penalties; the imposition of investigatory, remedial or corrective action obligations or the incurrence of capital expenditures; the occurrence of delays in the permitting, development or expansion of projects and the issuance of injunctive relief limiting or prohibiting Company activities. Moreover, certain of these laws impose joint and several, strict liability for costs required to remediate and restore sites where petroleum hydrocarbons, wastes or other materials have been released or disposed. In addition, new laws and regulations, new interpretations of existing laws and regulations, increased governmental enforcement or other developments, some of which legal requirements are discussed below, could significantly increase the Company’s operational or compliance expenditures.
Remediation of subsurface contamination is in process at certain of the Company’s refinery sites and is being overseen by the appropriate state agencies. Based on current investigative and remedial activities, the Company believes that the soil and groundwater contamination at these refineries can be controlled or remediated without having a material adverse effect on the Company’s financial condition. However, such costs are often unpredictable and, therefore, there can be no assurance that the future costs will not become material.
San Antonio Refinery
In connection with the acquisition of the San Antonio refinery, the Company agreed to indemnify NuStar for an unlimited term and without consideration of a monetary deductible or cap from any environmental liabilities associated with the San Antonio refinery, except for any governmental penalties or fines that may result from NuStar’s actions or inactions during NuStar’s 20-month period of ownership of the San Antonio refinery. Anadarko Petroleum Corporation (“Anadarko”) and Age Refining, Inc. (“Age Refining”), a third party that has since entered bankruptcy, are subject to a 1995 Agreed Order from the Texas Natural Resource Conservation Commission, now known as the Texas Commission on Environmental Quality, pursuant to which Anadarko and Age Refining are obligated to assess and remediate certain contamination at the San Antonio refinery that predates the Company’s acquisition of the facility. The Company does not expect this pre-existing contamination at the San Antonio refinery to have a material adverse effect on its financial position or results of operations.
Great Falls Refinery
In connection with the acquisition of the Great Falls refinery from Connacher Oil and Gas Limited (“Connacher”), the Company became a party to an existing 2002 Refinery Initiative Consent Decree (the “Great Falls Consent Decree”) with the EPA and the Montana Department of Environmental Quality (the “MDEQ”). The material obligations imposed by the Great Falls Consent Decree have been completed. On September 27, 2012, Montana Refining Company, Inc. received a final Corrective Action Order on Consent, replacing the refinery’s previously held hazardous waste permit. This Corrective Action Order on Consent governs the investigation and remediation of contamination at the Great Falls refinery. The Company believes the majority of damages related to such contamination at the Great Falls refinery are covered by a contractual indemnity provided by HollyFrontier Corporation (“Holly”), the owner and operator of the Great Falls refinery prior to its acquisition by Connacher, under an asset purchase agreement between Holly and Connacher, pursuant to which Connacher acquired the Great Falls refinery. Under this asset purchase agreement, Holly agreed to indemnify Connacher and Montana Refining Company, Inc., subject to timely notification, certain conditions and certain monetary baskets and caps, for environmental conditions arising under Holly’s ownership and operation of the Great Falls refinery and existing as of the date of sale to Connacher. During 2014, Holly provided the Company a notice challenging the Company’s position that Holly is obligated to indemnify the Company’s remediation expenses for environmental conditions to the extent arising under Holly’s ownership and operation of the refinery and existing as of the date of sale to Connacher, which expenditures totaled approximately $18.7 million as of June 30, 2017, of which $14.6 million was capitalized into the cost of the Company’s recently completed refinery expansion project and $4.1 million was expensed. The Company continues to believe that Holly is responsible to indemnify the Company for these remediation expenses disputed by Holly and on September 22, 2015, the Company initiated a lawsuit against Holly and the sellers of the Great Falls refinery under the asset purchase agreement. On November 24, 2015, Holly and the sellers of the Great Falls refinery under the asset purchase agreement filed a motion to dismiss the case pending arbitration. On February 10, 2016, the court ordered that all of the claims be addressed in arbitration. Arbitration is scheduled for early 2018. In the event the Company is unsuccessful in the legal dispute with Holly, the Company will be responsible for the remediation expenses. The Company expects that it may incur costs to remediate other environmental conditions at the Great Falls refinery; however, the costs cannot be estimated at this time. The Company believes at this time that these other costs it may incur will not be material to its financial position or results of operations.

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Superior Refinery
In connection with the acquisition of the Superior refinery, the Company became a party to an existing Refinery Initiative Consent Decree (“Superior Consent Decree”) with the EPA and the Wisconsin Department of Natural Resources (“WDNR”) that applies, in part, to its Superior refinery. Under the Superior Consent Decree, the Company must complete certain reductions in air emissions at the Superior refinery as well as report upon certain emissions from the refinery to the EPA and the WDNR. As of June 30, 2017, the Company estimates costs of up to $6.0 million to make known equipment upgrades and conduct other discrete tasks in compliance with the Superior Consent Decree. Failure to perform these required tasks under the Superior Consent Decree could result in the imposition of stipulated penalties, which could be material. The Company is currently assessing certain past actions at the refinery for compliance with the terms of the Superior Consent Decree, which actions may be subject to stipulated penalties under the Superior Consent Decree but, in any event, the Company does not currently believe that the imposition of such penalties for those actions, should they be imposed, would be material. In addition, the Company is pursuing certain additional environmental and safety-related projects at the Superior refinery. Completion of these additional projects will result in the Company incurring additional costs, which could be substantial. For the three and six months ended June 30, 2017 and 2016, the Company incurred costs of $0.1 million and less than $0.1 million, respectively, related to installing process equipment at the Superior refinery pursuant to EPA fuel content regulations.
In June 2012, the EPA issued a Finding of Violation/Notice of Violation to the Superior refinery, which included a proposed penalty amount of $0.1 million. This finding is in response to information provided to the EPA by the Company in response to an information request. The EPA alleges that the efficiency of the flares at the Superior refinery is lower than regulatory requirements. The Company is contesting the allegations and is in settlement discussions with the EPA to resolve this issue. The Company has not yet received formal action from the EPA. The Company does not believe that the resolution of these allegations will have a material adverse effect on its financial position or results of operations.
The Company is contractually indemnified by Murphy Oil Corporation (“Murphy Oil”) under an asset purchase agreement between the Company and Murphy Oil for specified environmental liabilities arising from the operation of the Superior refinery including: (i) certain obligations arising out of the Superior Consent Decree (including payment of a civil penalty required under the Superior Consent Decree), (ii) certain liabilities arising in connection with Murphy Oil’s transport of certain wastes and other materials to specified offsite real properties for disposal or recycling prior to the acquisition of Superior and (iii) certain liabilities for certain third-party actions, suits or proceedings alleging exposure, prior to the acquisition of Superior, of an individual to wastes or other materials at the specified on-site real property, which wastes or other materials were spilled, released, emitted or otherwise discharged by Murphy Oil. The Company believes contractual indemnity by Murphy Oil for such specified environmental liabilities is unlimited in duration and not subject to any monetary deductibles or maximums. The amount of any damages payable by Murphy Oil pursuant to the contractual indemnities under the asset purchase agreement are net of any amount recoverable under an environmental insurance policy that the Company obtained in connection with the acquisition of the Superior refinery, which named the Company and Murphy Oil as insureds and covers environmental conditions existing at the Superior refinery prior to the Company’s acquisition of the Superior refinery.
Shreveport, Cotton Valley and Princeton Refineries
On December 23, 2010, the Company entered into a settlement agreement with the Louisiana Department of Environmental Quality (“LDEQ”) under LDEQ’s “Small Refinery and Single Site Refinery Initiative,” covering the Shreveport, Princeton and Cotton Valley refineries. This settlement agreement became effective on January 31, 2012. The settlement agreement, termed the “Global Settlement,” resolved alleged violations of the federal Clean Air Act, as amended (“CAA”), and federal Clean Water Act regulations that arose prior to December 23, 2010. Among other things, the Company agreed to complete beneficial environmental programs and implement emissions reduction projects at the Company’s Shreveport, Princeton and Cotton Valley refineries on an agreed-upon schedule. During the three months ended June 30, 2017, the Company incurred approximately $0.2 million of such capital expenditures. During the three months ended June 30, 2016, no such expenditures were incurred. During the six months ended June 30, 2017 and 2016, the Company incurred approximately $0.5 million and $0.4 million, respectively, of such capital expenditures. The Global Settlement is substantially complete and any remaining capital investment requirements will be incorporated into the Company’s annual capital expenditures budget. The Company does not expect any additional capital expenditures included in the Global Settlement to have a material adverse effect on the Company’s financial position or results of operations.
The Company is contractually indemnified by Shell Oil Company (“Shell”), as successor to Pennzoil-Quaker State Company, and Atlas Processing Company, under an asset purchase agreement between the Company and Shell, for specified environmental liabilities arising from the operations of the Shreveport refinery prior to the Company’s acquisition of the facility. The Company believes the contractual indemnity is unlimited in amount and duration, but requires the Company to contribute $1.0 million of the first $5.0 million of indemnified costs for certain of the specified environmental liabilities. The Company has recorded the $1.0 million liability in the condensed consolidated balance sheets.

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Bel-Ray Facility
Bel-Ray executed an Administrative Consent Order (“ACO”) with the New Jersey Department of Environmental Protection, effective January 4, 1994, which required investigation and remediation of contamination at or emanating from the Bel-Ray facility. In 2000, Bel-Ray entered into a fixed price remediation contract with Weston Solutions (“Weston”), a large remediation contractor, whereby Weston agreed to be fully liable for the remediation of the soil and groundwater issues at the facility, including an offsite groundwater plume pursuant to the ACO (“Weston Agreement”). The Weston Agreement set up a trust fund to reimburse Weston, administered by Bel-Ray’s environmental counsel. As of June 30, 2017, the trust fund contained approximately $0.6 million. In addition, Weston has remediation cost containment insurance, should Weston be unable to complete the work required under the Weston Agreement. In connection with the acquisition of Bel-Ray, the Company became a party to the Weston Agreement.
Weston has been addressing the environmental issues at the Bel-Ray facility over time and the next phase will address the groundwater issues, which extend offsite.
Renewable Identification Numbers Obligation
On February 10, 2017 and on May 4, 2017, the EPA granted certain of the Company’s refineries a “small refinery exemption” under the RFS for the full-year 2016, as provided for under the federal Clean Air Act, as amended (“CAA”). In granting those exemptions, the EPA determined that for the full-year 2016 compliance with the RFS would represent a “disproportionate economic hardship” for these refineries.
As of June 30, 2017 and December 31, 2016, the Company had a RINs Obligation of $25.6 million and $79.3 million, respectively. RINs gain for the three and six months ended June 30, 2017 was $16.5 million and $64.1 million, respectively, as compared to a RINs expense for the same periods in 2016 of $8.2 million and $25.0 million, respectively.
Occupational Health and Safety
The Company is subject to various laws and regulations relating to occupational health and safety, including OSHA and comparable state laws. These laws and regulations strictly govern the protection of the health and safety of employees. In addition, OSHA’s hazard communication standard requires that information be maintained about hazardous materials used or produced in the Company’s operations and that this information be provided to employees, contractors, state and local government authorities and customers. The Company maintains safety and training programs as part of its ongoing efforts to promote compliance with applicable laws and regulations. The Company conducts periodic audits of Process Safety Management (“PSM”) systems at each of its locations subject to the PSM standard. The Company’s compliance with applicable health and safety laws and regulations has required, and continues to require, substantial expenditures. Changes in occupational safety and health laws and regulations or a finding of non-compliance with current laws and regulations could result in additional capital expenditures or operating expenses, as well as civil penalties and, in the event of a serious injury or fatality, criminal charges.
In the first quarter of 2011, OSHA conducted an inspection of the Cotton Valley refinery’s PSM program. On March 14, 2011, OSHA issued a Citation and Notification of Penalty (the “Cotton Valley Citation”) to the Company as a result of the Cotton Valley inspection, which included a proposed penalty amount of $0.2 million. The Company has contested the Cotton Valley Citation and the parties have reached a tentative settlement with OSHA on the matter, which the Company does not believe will have a material adverse effect on its financial position or results of operations.
Legal Proceedings
The Company is subject to claims and litigation arising in the normal course of its business. The Company has recorded accruals with respect to certain of these matters, where appropriate, that are reflected in the unaudited condensed consolidated financial statements but are not individually considered material. For other matters, the Company has not recorded accruals because it has not yet determined that a loss is probable or because the amount of loss cannot be reasonably estimated. While the ultimate outcome of claims and litigation currently pending cannot be determined, the Company currently does not expect that these proceedings and claims, individually or in the aggregate (including matters for which the Company has recorded accruals), will have a material adverse effect on its financial position, results of operations or cash flows. The outcome of any litigation is inherently uncertain, however, and if decided adversely to the Company, or if the Company determines that settlement of particular litigation is appropriate, the Company may be subject to liability that could have a material adverse effect on its financial position, results of operations or cash flows.

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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, 2017 and December 31, 2016, the Company had outstanding standby letters of credit of $97.1 million and $82.1 million, respectively, under its senior secured revolving credit facility (the “revolving credit facility”). Refer to Note 7 for additional information regarding the Company’s revolving credit facility. At June 30, 2017 and December 31, 2016, the maximum amount of letters of credit the Company could issue under its revolving credit facility was subject to borrowing base limitations, with a maximum letter of credit sublimit equal to $600.0 million, which amount may be increased to 90% of revolver commitments in effect ($900.0 million at June 30, 2017 and December 31, 2016) with the consent of the Agent (as defined in the revolving credit facility agreement).
As of June 30, 2017 and December 31, 2016, the Company had availability to issue letters of credit of $342.1 million and $360.8 million, respectively, under its revolving credit facility.
6. Inventory Financing Agreements
On March 31, 2017, the Company entered into several agreements with Macquarie to support the operations of the Great Falls refinery (the “Great Falls Supply and Offtake Agreements”). The Great Falls Supply and Offtake Agreements expire on October 31, 2019. On July 27, 2017, the Company amended the Great Falls Supply and Offtake Agreements to provide Macquarie the option to terminate the Great Falls Supply and Offtake Agreements with nine months notice any time prior to June 2019.
On June 19, 2017, the Company entered into several agreements with Macquarie to support the operations of the Shreveport refinery (the “Shreveport Supply and Offtake Agreements”, and together with the Great Falls Supply and Offtake Agreements, the “Supply and Offtake Agreements”). The Shreveport Supply and Offtake Agreements expire on June 2020; however, Macquarie has the option to terminate the Shreveport Supply and Offtake Agreements with nine months notice any time prior to June 2019.
At the commencement of the Great Falls Supply and Offtake Agreements, the Company sold to Macquarie inventory comprised of 652,000 barrels of crude oil and refined products valued at $32.2 million.
At the commencement of the Shreveport Supply and Offtake Agreements, the Company sold to Macquarie inventory comprised of 987,000 barrels of crude oil and refined products valued at $54.8 million.
In addition, the Company incurred approximately $3.0 million of costs related to the Supply and Offtake Agreements. These capitalized costs are recorded in obligations under inventory financing agreements in the Company’s condensed consolidated balance sheets and amortized to interest expense over the term of the agreement.
During the terms of the Supply and Offtake Agreements, the Company may purchase crude oil from Macquarie or one of its affiliates. Per the Supply and Offtake Agreements, Macquarie will provide up to 30,000 barrels per day of crude oil to the Great Falls refinery and 60,000 barrels per day of crude oil to the Shreveport refinery. The Company agreed to purchase the crude oil on a just-in-time basis to support the production operations at the Great Falls and Shreveport refineries. Additionally, the Company agreed to sell, and Macquarie agreed to buy, at market prices, refined products produced at the Great Falls and Shreveport refineries. For Shreveport finished products consisting of finished fuel products (other than jet fuel), lubricants and waxes, Macquarie may (but is not required to) sell such products to the sales intermediation party (“SIP”), and the SIP may (but is not required to) sell such products to Shreveport, as applicable, for sale in turn to third parties. For jet fuel and certain intermediate products, Macquarie may (but is not required to) sell such products to Shreveport for sale thereby to third parties. The Company will then repurchase the refined products from Macquarie or the SIP prior to selling the refined products to third parties.
The Supply and Offtake Agreements are subject to minimum and maximum inventory levels. The agreements also provide for the lease to Macquarie of crude oil and certain refined product storage tanks located at the Great Falls and Shreveport refineries and certain offsite locations. Following expiration or termination of the agreements, Macquarie has the option to require the Company to purchase the crude oil and refined product inventories then owned by Macquarie and located at the leased storage tanks at then current market prices. In addition, barrels owned by the Company are pledged as collateral to support the Deferred Payment Arrangement (defined below) obligations under these agreements.
While title to certain inventories will reside with Macquarie, the Supply and Offtake Agreements are accounted for by the Company similar to a product financing arrangement; therefore, the inventories sold to Macquarie will continue to be included in the Company’s condensed consolidated balance sheets until processed and sold to a third party. Each reporting period, the Company will record liabilities in an amount equal to the amount the Company expects to pay to repurchase the inventory held by Macquarie based on market prices at the termination date included in obligations under inventory financing agreements in the condensed consolidated balance sheets. The Company has determined that the redemption feature on the initially recognized liabilities related to the Supply and Offtake Agreements and the contingent interest feature are embedded derivatives indexed to commodity prices. As such, the Company has accounted for these embedded derivatives at fair value with changes in the fair value, if any, recorded in gain (loss) on derivative instruments in the Company’s unaudited condensed consolidated statements of operations. For more information on the valuation of the associated derivatives, see Note 8 - “Derivatives” and Note 9 - “Fair Value Measurements.”

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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, 2017, the Company incurred $0.4 million of financing costs related to the Supply and Offtake Agreements, which is included in interest expense in the Company’s unaudited condensed consolidated statements of operations.
The Company has provided collateral of $5.0 million related to the initial purchase of Great Falls and Shreveport inventory to cover credit risk for future crude oil deliveries and potential liquidation risk if Macquarie exercises its rights and sells the inventory to third parties. The collateral was recorded as a reduction to the obligations under inventory financing agreements pursuant to a master netting agreement.
The Supply and Offtake Agreements also include a deferred payment arrangement (“Deferred Payment Arrangement”) whereby the Company can defer payments on just-in-time crude oil purchases from Macquarie owed under the agreements up to the value of the collateral provided (90.0% of the collateral inventory) with the amount due always paid prior to the 20th of the month. The deferred amounts under the deferred payment arrangement will bear interest at a rate equal to LIBOR plus 3.25% or 2.65% per annum for Shreveport and Great Falls, respectively. Amounts outstanding under the Deferred Payment Arrangement are included in obligations under inventory financing agreements in the Company’s condensed consolidated balance sheets. Changes in the amount outstanding under the Deferred Payment Arrangement are included within cash flows from financing activities on the unaudited condensed consolidated statements of cash flows. As of June 30, 2017, the capacity of the Deferred Payment Arrangement was $16.3 million and the Company had $15.1 million deferred payments outstanding.
7. Long-Term Debt
Long-term debt consisted of the following (in millions):
 
June 30, 2017
 
December 31, 2016
Borrowings under amended and restated senior secured revolving credit agreement with third-party lenders, interest payments quarterly, borrowings due July 2019, weighted average interest rate of 6.1% and 4.8% for the six months ended June 30, 2017 and year ended December 31, 2016, respectively
$
0.4

 
$
10.2

Borrowings under 2021 Secured Notes, interest at a fixed rate of 11.50%, interest payments semiannually, borrowings due January 2021, effective interest rate of 12.3% and 12.2% for the six months ended June 30, 2017 and year ended December 31, 2016, respectively.
400.0

 
400.0

Borrowings under 2021 Notes, interest at a fixed rate of 6.50%, interest payments semiannually, borrowings due April 2021, effective interest rate of 6.8% for the six months ended June 30, 2017 and year ended December 31, 2016.
900.0


900.0

Borrowings under 2022 Notes, interest at a fixed rate of 7.625%, interest payments semiannually, borrowings due January 2022, effective interest rate of 8.0% for the six months ended June 30, 2017 and year ended December 31, 2016. (1)
352.3

 
352.5

Borrowings under 2023 Notes, interest at a fixed rate of 7.75%, interest payments semiannually, borrowings due April 2023, effective interest rate of 8.0% for the six months ended June 30, 2017 and year ended December 31, 2016.
325.0

 
325.0

Other
7.3

 
8.0

Capital lease obligations, at various interest rates, interest and principal payments monthly through November 2034
45.2

 
46.5

Less unamortized debt issuance costs (2)
(29.6
)
 
(33.2
)
Less unamortized discounts
(10.8
)
 
(11.8
)
Total long-term debt
$
1,989.8

 
$
1,997.2

Less current portion of long-term debt
3.4

 
3.5

 
$
1,986.4

 
$
1,993.7

 

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(1) 
The balance includes a fair value interest rate hedge adjustment, which increased the debt balance by $2.3 million and $2.5 million as of June 30, 2017 and December 31, 2016, respectively (refer to Note 8 for additional information on the interest rate swap designated as a fair value hedge).
(2) 
Deferred debt issuance costs are being amortized by the effective interest rate method over the lives of the related debt instruments. These amounts are net of accumulated amortization of $18.0 million and $14.5 million at June 30, 2017 and December 31, 2016, respectively.
Senior Notes
11.50% Senior Secured Notes (the “2021 Secured Notes”)
On April 20, 2016, the Company issued and sold $400.0 million in aggregate principal amount of 11.50% Senior Secured Notes due January 15, 2021, in a private placement pursuant to Section 4(a)(2) of the Securities Act of 1933, as amended (the “Securities Act”), to eligible purchasers at a discounted price of 98.273 percent of par. Subject to certain exceptions, the 2021 Secured Notes are secured by a lien on all of the fixed assets that secure the Company’s obligations under its secured hedge agreements, including certain present and future real property, fixtures and equipment; all U.S. registered patents and patent license rights, trademarks and trademark license rights, copyrights and copyright license rights and trade secrets; chattel paper, documents and instruments; certain cash deposits in the property, plant and equipment proceeds account; certain books and records; and all accessions and proceeds of any of the foregoing. The Company received net proceeds of approximately $382.5 million net of discount, initial purchasers’ fees and estimated expenses, which it used to repay borrowings outstanding under its revolving credit facility and for general partnership purposes, including planned capital expenditures at its facilities and working capital. Interest on the 2021 Secured Notes is paid semiannually in arrears on January 15 and July 15 of each year, beginning on July 15, 2016.
7.75% Senior Notes (the “2023 Notes”)
On March 27, 2015, the Company issued and sold $325.0 million in aggregate principal amount of 7.75% Senior Notes due April 15, 2023, in a private placement pursuant to Section 4(a)(2) of the Securities Act, to eligible purchasers at a discounted price of 99.257 percent of par. The Company received net proceeds of approximately $317.0 million net of discount, initial purchasers’ fees and expenses, which the Company used to fund the redemption of $178.8 million in aggregate principal amount of outstanding 9.625% senior notes due 2020 on April 28, 2015, to repay borrowings outstanding under its revolving credit facility and for general partnership purposes, including planned capital expenditures at the Company’s facilities and working capital. Interest on the 2023 Notes is paid semiannually in arrears on April 15 and October 15 of each year, beginning on October 15, 2015.
6.50% Senior Notes (the “2021 Notes”)
On March 31, 2014, the Company issued and sold $900.0 million in aggregate principal amount of 6.50% Senior Notes due April 15, 2021, in a private placement pursuant to Section 4(a)(2) of the Securities Act, to eligible purchasers at par. The Company received net proceeds of approximately $884.0 million net of initial purchasers’ fees and expenses, which the Company used to fund the purchase price of ADF Holdings, Inc., the parent company of Anchor Drilling Fluids USA, Inc. (subsequently converted to ADF Holdings, LLC and Anchor Drilling Fluids USA, LLC), the redemption of $500.0 million in aggregate principal amount outstanding of 9.375% Senior Notes due 2019 and for general partnership purposes, including planned capital expenditures at the Company’s facilities. Interest on the 2021 Notes is paid semiannually in arrears on April 15 and October 15 of each year, beginning on October 15, 2014.
7.625% Senior Notes (the “2022 Notes”)
On November 26, 2013, the Company issued and sold $350.0 million in aggregate principal amount of 7.625% Senior Notes due January 15, 2022, in a private placement pursuant to Section 4(a)(2) of the Securities Act, to eligible purchasers at a discounted price of 98.494 percent of par. The Company received net proceeds of approximately $337.4 million, net of discount, initial purchasers’ fees and expenses, which the Company used for general partnership purposes, to fund previously announced organic growth projects, the purchase price of the Bel-Ray acquisition and the redemption of $100.0 million in aggregate principal amount outstanding of 9.375% Senior Notes due 2019. Interest on the 2022 Notes is paid semiannually in arrears on January 15 and July 15 of each year, beginning on July 15, 2014.

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2021 Secured Notes, 2021 Notes, 2022 Notes and 2023 Notes
In accordance with SEC Rule 3-10 of Regulation S-X, unaudited condensed consolidated financial statements of non-guarantors are not required. The Company has no assets or operations independent of its subsidiaries. Obligations under its 2021, 2022 and 2023 Notes are fully and unconditionally and jointly and severally guaranteed on a senior unsecured basis by the Company’s current 100%-owned operating subsidiaries and certain of the Company’s future operating subsidiaries, with the exception of the Company’s “minor” subsidiaries (as defined by Rule 3-10 of Regulation S-X), including Calumet Finance Corp. (100%-owned Delaware corporation that was organized for the sole purpose of being a co-issuer of certain of the Company’s indebtedness, including the 2021 Secured, 2021, 2022 and 2023 Notes). There are no significant restrictions on the ability of the Company or subsidiary guarantors for the Company to obtain funds from its subsidiary guarantors by dividend or loan. None of the subsidiary guarantors’ assets represent restricted assets pursuant to SEC Rule 4-08(e)(3) of Regulation S-X.
The 2021 Secured, 2021, 2022 and 2023 Notes are subject to certain automatic customary releases, including the sale, disposition or transfer of capital stock or substantially all of the assets of a subsidiary guarantor, designation of a subsidiary guarantor as unrestricted in accordance with the applicable indenture, exercise of legal defeasance option or covenant defeasance option, liquidation or dissolution of the subsidiary guarantor and a subsidiary guarantor ceases to both guarantee other Company debt and to be an obligor under the revolving credit facility. The Company’s operating subsidiaries may not sell or otherwise dispose of all or substantially all of their properties or assets to, or consolidate with or merge into, another company if such a sale would cause a default under the indentures governing the 2021 Secured, 2021, 2022 and 2023 Notes.
The indentures governing the 2021 Secured, 2021, 2022 and 2023 Notes contain covenants that, among other things, restrict the Company’s ability and the ability of certain of the Company’s subsidiaries to: (i) sell assets; (ii) pay distributions on, redeem or repurchase the Company’s common units or redeem or repurchase its subordinated debt or, in the case of the 2021 Secured Notes, its unsecured notes; (iii) make investments; (iv) incur or guarantee additional indebtedness or issue preferred units; (v) create or incur certain liens; (vi) enter into agreements that restrict distributions or other payments from the Company’s restricted subsidiaries to the Company; (vii) consolidate, merge or transfer all or substantially all of the Company’s assets; (viii) engage in transactions with affiliates and (ix) create unrestricted subsidiaries. These covenants are subject to important exceptions and qualifications. At any time when the 2021 Secured, 2021, 2022 and 2023 Notes are rated investment grade by either Moody’s Investors Service, Inc. (“Moody’s”) or S&P Global Ratings (“S&P”) and no Default or Event of Default, each as defined in the indentures governing the 2021 Secured, 2021, 2022 and 2023 Notes, has occurred and is continuing, many of these covenants will be suspended. As of June 30, 2017, the Company’s Fixed Charge Coverage Ratio (as defined in the indentures governing the 2021 Secured, 2021, 2022 and 2023 Notes) was 1.5 to 1.0. As of June 30, 2017, the Company was in compliance with all covenants under the indentures governing the 2021 Secured, 2021, 2022 and 2023 Notes.
Second Amended and Restated Senior Secured Revolving Credit Facility
The Company has a $900.0 million senior secured revolving credit facility, subject to borrowing base limitations, which includes a $500.0 million incremental uncommitted expansion feature. The revolving credit facility is the Company’s primary source of liquidity for cash needs in excess of cash generated from operations. The revolving credit facility matures in July 2019 and currently bears interest at a rate equal to either the prime rate plus a basis points margin or the London Interbank Offered Rate (“LIBOR”) plus a basis points margin, at the Company’s option. As of June 30, 2017, the margin was 50 basis points for prime rate loans and 150 basis points for LIBOR rate loans; however, the margin can fluctuate quarterly based on the Company’s average availability for additional borrowings under the revolving credit facility in the preceding fiscal quarter.
On March 31, 2017, the Company amended its revolving credit facility to allow for the entry into the Supply and Offtake Agreements at the Great Falls refinery. The amendment resulted in the release of certain Eligible Inventory (as defined in the revolving credit facility agreement) from the revolving credit facility as that inventory is now collateral under the Supply and Offtake Agreements. For additional discussion of the Supply and Offtake Agreements, refer to Note 6.
In addition to paying interest quarterly on outstanding borrowings under the revolving credit facility, the Company is required to pay a commitment fee to the lenders under the revolving credit facility with respect to the unutilized commitments thereunder at a rate equal to 0.250% or 0.375% per annum, depending on the average daily available unused borrowing capacity for the preceding month. The Company also pays a customary letter of credit fee, including a fronting fee of 0.125% per annum of the stated amount of each outstanding letter of credit and customary agency fees.
The borrowing capacity as of June 30, 2017 under the revolving credit facility was $439.6 million. As of June 30, 2017, the Company had $0.4 million in outstanding borrowings under the revolving credit facility and outstanding standby letters of credit of $97.1 million, leaving $342.1 million available for additional borrowings based on specified availability limitations. Lenders under the revolving credit facility have a first priority lien on the Company’s accounts receivable, certain inventory and substantially all of its cash (collectively, the “Credit Agreement Collateral”).
The revolving credit facility contains various covenants that limit, among other things, the Company’s ability to: incur indebtedness; grant liens; dispose of certain assets; make certain acquisitions and investments; redeem or prepay other debt or

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make other restricted payments such as distributions to unitholders; enter into transactions with affiliates and enter into a merger, consolidation or sale of assets. Further, the revolving credit facility contains one springing financial covenant which provides that only if the Company’s availability under the revolving credit facility falls below the greater of (a) 12.5% of the Borrowing Base (as defined in the revolving credit agreement) then in effect and (b) $45.0 million (which amount is subject to increase in proportion to revolving commitment increases), then the Company will be required to maintain as of the end of each fiscal quarter a Fixed Charge Coverage Ratio (as defined in the revolving credit agreement) of at least 1.0 to 1.0.
As of June 30, 2017, the Company was in compliance with all covenants under the revolving credit facility.
Maturities of Long-Term Debt
As of June 30, 2017, principal payments on debt obligations and future minimum rentals on capital lease obligations are as follows (in millions):
Year
Maturity
2017
$
1.7

2018
4.2

2019
3.2

2020
2.4

2021
1,303.3

Thereafter
713.1

Total
$
2,027.9

8. Derivatives
The Company is exposed to price risks due to fluctuations in the price of crude oil, refined products (primarily in the Company’s fuel products segment), natural gas and precious metals. The Company uses various strategies to reduce its exposure to commodity price risk. The strategies to reduce the Company’s risk utilize both physical forward contracts and financially settled derivative instruments, such as swaps, collars, options and futures, to attempt to reduce the Company’s exposure with respect to:
•
crude oil purchases and sales;
•
fuel product sales and purchases;
•
natural gas purchases;
•
precious metals purchases; and
•
fluctuations in the value of crude oil between geographic regions and between the different types of crude oil such as New York Mercantile Exchange West Texas Intermediate (“NYMEX WTI”), Light Louisiana Sweet (“LLS”), Western Canadian Select (“WCS”), Mixed Sweet Blend (“MSW”) and ICE Brent.
The Company manages its exposure to commodity markets, credit, volumetric and liquidity risks to manage its costs and volatility of cash flows as conditions warrant or opportunities become available. These risks may be managed in a variety of ways that may include the use of derivative instruments. Derivative instruments may be used for the purpose of mitigating risks associated with an asset, liability and anticipated future transactions and the changes in fair value of the Company’s derivative instruments will affect its earnings and cash flows; however, such changes should be offset by price or rate changes related to the underlying commodity or financial transaction that is part of the risk management strategy. The Company does not speculate with derivative instruments or other contractual arrangements that are not associated with its business objectives. Speculation is defined as increasing the Company’s natural position above the maximum position of its physical assets or trading in commodities, currencies or other risk bearing assets that are not associated with the Company’s business activities and objectives. The Company’s positions are monitored routinely by a risk management committee to maintain compliance with its stated risk management policy and documented risk management strategies. All strategies are reviewed on an ongoing basis by the Company’s risk management committee, which will add, remove or revise strategies in anticipation of changes in market conditions and/or its risk profiles. Such changes in strategies are to position the Company in relation to its risk exposures in an attempt to capture market opportunities as they arise. 
The Company is obligated to repurchase crude oil and refined products from Macquarie at the termination of the Supply and Offtake Agreements in certain scenarios. The Company has determined that the redemption feature on the initially recognized liability related to the Supply and Offtake Agreements and the contingent interest feature are embedded derivatives indexed to commodity prices. As such, the Company has accounted for these embedded derivatives at fair value with changes in the fair value, if any, recorded in gain (loss) on derivative instruments in the Company’s unaudited condensed consolidated statements of operations.

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The Company recognizes all derivative instruments at their fair values (see Note 9) as either current assets or current liabilities in the condensed consolidated balance sheets. Fair value includes any premiums paid or received and unrealized gains and losses. Fair value does not include any amounts receivable from or payable to counterparties, or collateral provided to counterparties. Derivative asset and liability amounts with the same counterparty are netted against each other for financial reporting purposes.
The following tables summarize the Company’s gross fair values of its derivative instruments, presenting the impact of offsetting derivative assets in the Company’s condensed consolidated balance sheets as of June 30, 2017, and December 31, 2016 (in millions):
 
 
 
 
June 30, 2017
 
December 31, 2016
 
 
Balance Sheet Location
 
Gross Amounts of Recognized Assets
 
Gross Amounts Offset in the Condensed Consolidated Balance Sheets
 
Net Amounts of Assets Presented
in the Condensed Consolidated Balance Sheets
 
Gross Amounts of Recognized Assets
 
Gross Amounts Offset in the Condensed Consolidated Balance Sheets
 
Net Amounts of Assets Presented
in the Condensed Consolidated Balance Sheets
Derivative instruments not designated as hedges:
 
 
 
 
 
 
 
 
 
 
Specialty products segment:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Natural gas swaps
 
Derivative assets
 
$
—

 
$
(0.8
)
 
$
(0.8
)
 
$
0.1

 
$
(0.1
)
 
$
—

Fuel products segment:
 
 
 
 
 
 
 


 
 
 
 
 
 
Crude oil swaps
 
Derivative assets
 
1.2

 
(2.1
)
 
(0.9
)
 
10.3

 
(7.4
)
 
2.9

Crude oil basis swaps
 
Derivative assets
 
2.2

 
0.1

 
2.3

 
—

 
(2.1
)
 
(2.1
)
Crude oil percentage basis swaps
 
Derivative assets
 
0.8

 
(0.4
)
 
0.4

 
0.1

 
(0.1
)
 
—

Total derivative instruments
 
 
 
$
4.2


$
(3.2
)

$
1.0


$
10.5


$
(9.7
)

$
0.8

The following tables summarize the Company’s gross fair values of its derivative instruments, presenting the impact of offsetting derivative liabilities in the Company’s condensed consolidated balance sheets as of June 30, 2017, and December 31, 2016 (in millions):
 
 
 
 
June 30, 2017
 
December 31, 2016
 
 
Balance Sheet Location
 
Gross Amounts of Recognized Liabilities
 
Gross Amounts Offset in the Condensed Consolidated Balance Sheets
 
Net Amounts of Liabilities Presented
in the Condensed Consolidated Balance Sheets
 
Gross Amounts of Recognized Liabilities
 
Gross Amounts Offset in the Condensed Consolidated Balance Sheets
 
Net Amounts of Liabilities Presented
in the Condensed Consolidated Balance Sheets
Derivative instruments not designated as hedges:
 
 
 
 
 
 
 
 
 
 
Specialty products segment:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Natural gas swaps
 
Derivative liabilities
 
$
(1.6
)
 
$
0.8

 
$
(0.8
)
 
$
(1.2
)
 
$
0.1

 
$
(1.1
)
Fuel products segment:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Inventory financing obligation
 
Obligations under inventory financing agreements
 
(0.9
)
 
—

 
(0.9
)
 
—

 
—

 
—

Crude oil swaps
 
Derivative liabilities
 
(3.8
)
 
2.1

 
(1.7
)
 
(8.2
)
 
7.4

 
(0.8
)
Crude oil basis swaps
 
Derivative liabilities
 
0.1

 
(0.1
)
 
—

 
(7.1
)
 
2.1

 
(5.0
)
Crude oil percentage basis swaps
 
Derivative liabilities
 
—

 
0.4

 
0.4

 
(0.6
)
 
0.1

 
(0.5
)
Gasoline crack spread swaps
 
Derivative liabilities
 
—

 
—

 
—

 
(3.5
)
 
—

 
(3.5
)
Diesel crack spread swaps
 
Derivative liabilities
 
—

 
—

 
—

 
(1.4
)
 
—

 
(1.4
)
2/1/1 crack spread swaps
 
Derivative liabilities
 
—

 
—

 
—

 
(2.5
)
 
—

 
(2.5
)
Total derivative instruments
 
 
$
(6.2
)
 
$
3.2

 
$
(3.0
)
 
$
(24.5
)
 
$
9.7

 
$
(14.8
)
The Company is exposed to credit risk in the event of nonperformance by its counterparties on these derivative transactions. The Company does not expect nonperformance on any derivative instruments, however, no assurances can be provided. The Company’s

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credit exposure related to these derivative instruments is represented by the fair value of contracts reported as derivative assets. As of June 30, 2017, the Company had three counterparties in which the derivatives held were net assets, totaling $1.0 million. As of December 31, 2016, the Company had one counterparty in which the derivatives held were net assets, totaling $0.8 million. To manage credit risk, the Company selects and periodically reviews counterparties based on credit ratings. The Company primarily executes its derivative instruments with large financial institutions that have ratings of at least Baa2 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, 2017 or December 31, 2016. Collateral received from counterparties is reported in other current liabilities, and collateral held by counterparties is reported in prepaid expenses and other current assets on the Company’s condensed consolidated balance sheets and is not netted against derivative assets or liabilities. Any outstanding collateral is released to the Company upon settlement of the related derivative instrument liability. As of June 30, 2017 and December 31, 2016, the Company had provided no collateral to its counterparties.
Certain of the Company’s outstanding derivative instruments are subject to credit support agreements with the applicable counterparties which contain provisions setting certain credit thresholds above which the Company may be required to post agreed-upon collateral, such as cash or letters of credit, with the counterparty to the extent that the Company’s mark-to-market net liability, if any, on all outstanding derivatives exceeds the credit threshold amount per such credit support agreement. The majority of the credit support agreements covering the Company’s outstanding derivative instruments also contain a general provision stating that if the Company experiences a material adverse change in its business, in the reasonable discretion of the counterparty, the Company’s credit threshold could be lowered by such counterparty. The Company does not expect that it will experience a material adverse change in its business.
The cash flow impact of the Company’s commodity derivative activities is classified primarily as a change in derivative activity in the operating activities section in the unaudited condensed consolidated statements of cash flows. The cash flow impact of the Company’s embedded derivatives included in the Supply and Offtake Agreements is classified as a change in derivative activity in the investing activities section in the unaudited condensed consolidated statements of cash flows.
Derivative Instruments Designated as Cash Flow Hedges
Prior to 2017, the Company accounted for certain derivatives hedging purchases of crude oil and sales of diesel swaps as cash flow hedges. As of June 30, 2017, the Company has no derivative instruments designated as cash flow hedges. The derivative instruments designated as cash flow hedges that are hedging sales and purchases are recorded to sales and cost of sales, respectively, in the unaudited condensed consolidated statements of operations upon recording the related hedged transaction in sales or cost of sales. The Company assesses, both at inception of the cash flow hedge and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items. Periodically, the Company may enter into crude oil and fuel product basis swaps to more effectively hedge its crude oil purchases, crude oil sales and fuel products sales. These derivatives can be combined with a swap contract in order to create a more effective cash flow hedge. 
To the extent a derivative instrument designated as a cash flow hedge is determined to be effective as a cash flow hedge of an exposure to changes in the fair value of a future transaction, the change in fair value of the derivative is deferred in accumulated other comprehensive income (loss), a component of partners’ capital in the condensed consolidated balance sheets, until the underlying transaction hedged is recognized in the unaudited condensed consolidated statements of operations.
Ineffectiveness is inherent in the hedging of crude oil and fuel products. Due to the volatility in the markets for crude oil and fuel products, the Company is unable to predict the amount of ineffectiveness each period, determined on a derivative by derivative basis or in the aggregate for a specific commodity and has the potential for the future loss of cash flow hedge accounting. Ineffectiveness has resulted, and the loss of cash flow hedge accounting has resulted, in increased volatility in the Company’s financial results. However, even though certain derivative instruments may not qualify for cash flow hedge accounting, the Company intends to continue to utilize such instruments as management believes such derivative instruments continue to provide the Company with the opportunity to more effectively stabilize cash flows.
Cash flow hedge accounting is discontinued when it is determined that a derivative no longer qualifies as an effective hedge or when it is no longer probable that the hedged forecasted transaction will occur. When cash flow hedge accounting is discontinued because the derivative instrument no longer qualifies as an effective cash flow hedge, the derivative instrument is subject to the mark-to-market method of accounting prospectively. Changes in the mark-to-market fair value of the derivative instrument are recorded to gain (loss) on derivative instruments in the unaudited condensed consolidated statements of operations. Unrealized gains and losses related to discontinued cash flow hedges that were previously deferred in accumulated other comprehensive income (loss) will remain in accumulated other comprehensive income (loss) until the underlying transaction is reflected in earnings, unless it is probable that the hedged forecasted transaction will not occur, at which time, associated deferred amounts in accumulated other comprehensive income (loss) are immediately recognized in gain (loss) on derivative instruments in the unaudited condensed consolidated statements of operations.

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The Company recorded the following amounts in its condensed consolidated balance sheets, unaudited condensed consolidated statements of operations, unaudited condensed consolidated statements of comprehensive loss and unaudited condensed consolidated statements of partners’ capital as of and for the three months ended June 30, 2017 and 2016, related to its derivative instruments that were designated as cash flow hedges (in millions):
Type of Derivative
Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Loss on Derivatives (Effective Portion)
 
Amount of Gain (Loss) Reclassified from Accumulated Other Comprehensive Loss into Net Income (Loss) (Effective Portion)
 
Amount of Gain (Loss) Recognized in Net Income (Loss) on Derivatives (Ineffective Portion)
Three Months Ended
 
Location of Gain (Loss)
 
Three Months Ended
 
Location of Gain (Loss)
 
Three Months Ended
June 30,
 
 
June 30,
 
 
June 30,
2017
 
2016
 
 
2017
 
2016
 
 
2017
 
2016
Specialty products segment:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil swaps
$
—

 
$
—

 
Cost of sales
 
$
—

 
$
(0.5
)
 
Gain (loss) on derivative instruments
 
$
—

 
$
—

Fuel products segment:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil swaps
—

 
(4.5
)
 
Cost of sales
 
—

 
(12.3
)
 
Gain (loss) on derivative instruments
 
—

 
—

Diesel swaps
—

 
4.5

 
Sales
 
—

 
15.1

 
Gain (loss) on derivative instruments
 
—

 
—

Total
$
—

 
$
—

 
 
 
$
—

 
$
2.3

 
 
 
$
—

 
$
—

The Company recorded the following amounts in its condensed consolidated balance sheets, unaudited condensed consolidated statements of operations, unaudited condensed consolidated statements of comprehensive income (loss) and unaudited condensed consolidated statements of partners’ capital as of and for the six months ended June 30, 2017 and 2016, related to its derivative instruments that were designated as cash flow hedges (in millions):
Type of Derivative
Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Loss on Derivatives (Effective Portion)
 
Amount of Gain (Loss) Reclassified from Accumulated Other Comprehensive Loss into Net Income (Loss) (Effective Portion)
 
Amount of Gain (Loss) Recognized in Net Income (Loss) on Derivatives (Ineffective Portion)
Six Months Ended
 
Location of Gain (Loss)
 
Six Months Ended
 
Location of Gain (Loss)
 
Six Months Ended
June 30,
 
 
June 30,
 
 
June 30,
2017
 
2016
 
 
2017
 
2016
 
 
2017
 
2016
Specialty products segment:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil swaps
$
—

 
$
—

 
Cost of sales
 
$
—

 
$
(1.2
)
 
Gain (loss) on derivative instruments
 
$
—

 
$
—

Fuel products segment:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil swaps
—

 
(5.8
)
 
Cost of sales
 
—

 
(25.5
)
 
Gain (loss) on derivative instruments
 
—

 
—

Diesel swaps
—

 
5.8

 
Sales
 
—

 
31.1

 
Gain (loss) on derivative instruments
 
—

 
—

Total
$
—

 
$
—

 
 
 
$
—

 
$
4.4

 
 
 
$
—

 
$
—

As of June 30, 2017 and December 31, 2016, there was no effective portion of cash flow hedges classified in accumulated other comprehensive loss.
Derivative Instruments Designated as Fair Value Hedges
For derivative instruments that are designated and qualify as a fair value hedge (which are limited to interest rate swaps), the effective gain or loss on the derivative instrument, as well as the offsetting gain or loss on the hedged item attributable to the hedged risk are recognized as interest expense in the unaudited condensed consolidated statements of operations. No hedge ineffectiveness is recognized if the interest rate swap qualifies for the “shortcut” method and, as a result, changes in the fair value of the derivative instrument offset the changes in the fair value of the underlying hedged debt. In addition, the differential to be paid or received on the interest rate swap arrangement is accrued and recognized as an adjustment to interest expense in the unaudited condensed consolidated statements of operations. The Company assesses at the inception of the fair value hedge whether the derivatives that are used in the hedging transactions are highly effective in offsetting changes in fair values of hedged items.

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Fair value hedge accounting is discontinued when it is determined that a derivative no longer qualifies as an effective hedge or when it is no longer probable that the hedged forecasted transaction will occur. When fair value hedge accounting is discontinued because the derivative instrument no longer qualifies as an effective fair value hedge, the derivative instrument is still subject to mark-to-market method of accounting, however the Company will cease to adjust the hedged asset or liability for changes in fair value.
In 2014, the Company entered into an interest rate swap agreement which converted a portion of the Company’s fixed rate debt to a floating rate. This agreement involved the receipt of fixed rate amounts in exchange for floating rate interest payments over the life of the agreement without an exchange of the underlying principal amount. Also, in connection with the interest rate swap agreement, the Company entered into an option that permits the counterparty to cancel the interest rate swap for a specified premium. The Company designated this interest rate swap and option as a fair value hedge. On January 13, 2015, the Company terminated its interest rate swap, which was designated as a fair value hedge, related to a notional amount of $200.0 million of 2022 Notes. In settlement of this swap, the Company recognized a net gain of approximately $3.3 million.
The Company recorded the following losses in its unaudited condensed consolidated statements of operations for the three and six months ended June 30, 2017 and 2016, related to its derivative instrument designated as a fair value hedge (in millions):

Location of Loss of Derivative

Amount of Gain Recognized
in Net Income (Loss)

Hedged Item
 
Location of Gain on Hedged Item

Amount of Gain Recognized
in Net Income (Loss)

Three Months Ended June 30,

Six Months Ended June 30,


Three Months Ended June 30,

Six Months Ended June 30,

2017
 
2016

2017
 
2016


2017
 
2016

2017
 
2016
Swaps not allocated to a specific segment:
 



 



 
 


 
 
Interest rate swap
Interest expense

$
0.1

 
$
0.1


$
0.2

 
$
0.2


2022 Notes
 
Interest income

$
—

 
$
—


$
—

 
$
—

Total


$
0.1

 
$
0.1


$
0.2

 
$
0.2



 


$
—

 
$
—


$
—

 
$
—

Derivative Instruments Not Designated as Hedges
For derivative instruments not designated as hedges, the change in fair value of the asset or liability for the period is recorded to gain (loss) on derivative instruments in the unaudited condensed consolidated statements of operations. Upon the settlement of a derivative not designated as a hedge, the gain or loss at settlement is realized in the unaudited condensed consolidated statements of operations in gain (loss) on derivative instruments. Additionally, the Company has entered into natural gas swaps and certain other crude oil swaps that do not qualify as cash flow hedges for accounting purposes as they are determined not to be highly effective in offsetting changes in the cash flows associated with crude oil purchases and natural gas purchases and gasoline and diesel sales at the Company’s refineries.
The Company recorded the following gains (losses) in its unaudited condensed consolidated statements of operations for the three months ended June 30, 2017 and 2016, related to its derivative instruments not designated as hedges (in millions):
Type of Derivative
Amount of Realized Gain (Loss) Recognized in Gain (Loss) on Derivative Instruments
 
Amount of Unrealized Gain (Loss) Recognized in Gain (Loss) on Derivative Instruments
Three Months Ended June 30,
 
Three Months Ended June 30,
2017
 
2016
 
2017
 
2016
Specialty products segment:
 
 
 
 
 
 
 
Natural gas swaps
$
(0.9
)
 
$
(3.2
)
 
$
0.2

 
$
6.6

Natural gas collars
—

 
(0.4
)
 
—

 
0.5

Fuel products segment:
 
 
 
 
 
 
 
Inventory financing obligation
—

 
—

 
(0.9
)
 
—

Crude oil swaps
(1.1
)
 
0.1

 
(1.5
)
 
11.5

Crude oil basis swaps
1.4

 
0.1

 
3.2

 
(2.3
)
Crude oil percentage basis swaps
0.6

 
(0.5
)
 
0.3

 
5.2

Crude oil options
—

 
(1.5
)
 
—

 
0.8

Natural gas swaps
—

 
(0.6
)
 
—

 
1.5

Total
$
—

 
$
(6.0
)
 
$
1.3

 
$
23.8


24
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, 2017 and 2016, related to its derivative instruments not designated as hedges (in millions):
Type of Derivative
Amount of Realized Loss Recognized in Gain (Loss) on Derivative Instruments
 
Amount of Unrealized Gain (Loss) Recognized in Gain (Loss) on Derivative Instruments
Six Months Ended June 30,
 
Six Months Ended June 30,
2017
 
2016
 
2017
 
2016
Specialty products segment:
 
 
 
 
 
 
 
Natural gas swaps
$
(1.7
)
 
$
(6.6
)
 
$
(0.6
)
 
$
8.5

Natural gas collars
—

 
(0.7
)
 
—

 
0.6

Fuel products segment:
 
 
 
 
 
 
 
Inventory financing obligation
—

 
—

 
(0.9
)
 
—

Crude oil swaps
(1.5
)
 
(0.8
)
 
(4.8
)
 
13.0

Crude oil basis swaps
0.6

 
0.1

 
9.4

 
(4.9
)
Crude oil percentage basis swaps
0.6

 
(4.4
)
 
1.3

 
5.4

Crude oil options
—

 
(1.5
)
 
—

 
0.2

Crude oil futures
—

 
(2.0
)
 
—

 
—

Gasoline crack spread swaps
(1.6
)
 
(1.2
)
 
4.8

 
4.3

Diesel crack spread swaps
(0.3
)
 
—

 
2.7

 
—

2/1/1 crack spread swaps
(1.0
)
 
—

 
—

 
—

Natural gas swaps
—

 
(1.2
)
 
—

 
1.3

Total
$
(4.9
)
 
$
(18.3
)
 
$
11.9

 
$
28.4

Derivative Positions — Specialty Products Segment
Natural Gas Swap Contracts
At June 30, 2017, the Company had the following derivatives related to natural gas purchases in its specialty products segment, none of which are designated as hedges:
Natural Gas Swap Contracts by Expiration Dates
MMBtu

$/MMBtu
Third Quarter 2017
1,320,000

 
$
3.87

Fourth Quarter 2017
960,000

 
$
3.72

Total
2,280,000



Average price


$
3.81

At December 31, 2016, the Company had the following derivatives related to natural gas purchases in its specialty products segment, none of which are designated as hedges:
Natural Gas Swap Contracts by Expiration Dates
MMBtu

$/MMBtu
First Quarter 2017
1,350,000


$
3.88

Second Quarter 2017
1,320,000


$
3.87

Third Quarter 2017
1,320,000


$
3.87

Fourth Quarter 2017
960,000


$
3.72

Total
4,950,000



Average price


$
3.85


25
Table of Contents

Derivative Positions — Fuel Products Segment
Crude Oil Swap Contracts
At June 30, 2017, the Company had the following derivatives related to crude oil purchases in its fuel products segment, none of which are designated as hedges:
Crude Oil Swap Contracts by Expiration Dates
Barrels Purchased
 
BPD
 
Average Swap
($/Bbl)
Third Quarter 2017
327,161

 
3,556

 
$
48.87

Fourth Quarter 2017
327,161

 
3,556

 
$
48.87

Total
654,322


 
 
 
Average price
 
 
 

$
48.87

At June 30, 2017, the Company had the following derivatives related to crude oil sales in its fuel products segment, none of which are designated as hedges:
Crude Oil Swap Contracts by Expiration Dates
Barrels Sold
 
BPD
 
Average Swap
($/Bbl)
Third Quarter 2017
133,216

 
1,448

 
$
41.56

Fourth Quarter 2017
133,216

 
1,448

 
$
41.56

Total
266,432

 
 
 
 
Average price
 
 
 
 
$
41.56

At December 31, 2016, the Company had the following derivatives related to crude oil purchases in its fuel products segment, none of which are designated as hedges:
Crude Oil Swap Contracts by Expiration Dates
Barrels Purchased
 
BPD
 
Average Swap
($/Bbl)
First Quarter 2017
320,049

 
3,556

 
$
48.87

Second Quarter 2017
323,605

 
3,556

 
$
48.87

Third Quarter 2017
327,161

 
3,556

 
$
48.87

Fourth Quarter 2017
327,161

 
3,556

 
$
48.87

Total
1,297,976

 
 
 
 
Average price
 
 
 
 
$
48.87

At December 31, 2016, the Company had the following derivatives related to crude oil sales in its fuel products segment, none of which are designated as hedges:
Crude Oil Swap Contracts by Expiration Dates
Barrels Sold
 
BPD
 
Average Swap
($/Bbl)
First Quarter 2017
130,320

 
1,448

 
$
41.56

Second Quarter 2017
131,768

 
1,448

 
$
41.56

Third Quarter 2017
133,216

 
1,448

 
$
41.56

Fourth Quarter 2017
133,216

 
1,448

 
$
41.56

Total
528,520

 
 
 
 
Average price
 
 
 
 
$
41.56


26
Table of Contents

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, 2017, the Company had the following derivatives related to crude oil basis swaps in its fuel products segment, none of which are designated as hedges:
Crude Oil Basis Swap Contracts by Expiration Dates
Barrels Purchased
 
BPD
 
Average Differential to NYMEX WTI
($/Bbl)
Third Quarter 2017
644,000

 
7,000

 
$
(13.22
)
Fourth Quarter 2017
644,000

 
7,000

 
$
(13.22
)
Total
1,288,000

 
 
 
 
Average differential
 
 
 
 
$
(13.22
)
At December 31, 2016, the Company had the following derivatives related to crude oil basis swaps in its fuel products segment, none of which are designated as hedges:
Crude Oil Basis Swap Contracts by Expiration Dates
Barrels Purchased
 
BPD
 
Average Differential to NYMEX WTI
($/Bbl)
First Quarter 2017
630,000

 
7,000

 
$
(13.22
)
Second Quarter 2017
637,000

 
7,000

 
$
(13.22
)
Third Quarter 2017
644,000

 
7,000

 
$
(13.22
)
Fourth Quarter 2017
644,000

 
7,000

 
$
(13.22
)
Total
2,555,000

 
 
 
 
Average differential
 
 
 
 
$
(13.22
)
Crude Oil Percentage Basis Swap Contracts
The Company has entered into derivative instruments to secure a percentage differential of WCS crude oil to NYMEX WTI. At June 30, 2017, the Company had the following derivatives related to crude oil percentage basis swaps in its fuel products segment, none of which are designated as hedges:
Crude Oil Percentage Basis Swap Contracts by Expiration Dates
Barrels Purchased
 
BPD
 
Fixed Percentage of NYMEX WTI
(Average % of WTI/Bbl)
Third Quarter 2017
276,000

 
3,000

 
72.3
%
Fourth Quarter 2017
276,000

 
3,000

 
72.3
%
Total
552,000

 
 
 
 
Average percentage
 
 
 
 
72.3
%
At December 31, 2016, the Company had the following derivatives related to crude oil percentage basis swaps in its fuel products segment, none of which are designated as hedges:
Crude Oil Percentage Basis Swap Contracts by Expiration Dates
Barrels Purchased

BPD

Fixed Percentage of NYMEX WTI
(Average % of WTI/Bbl)
First Quarter 2017
270,000

 
3,000

 
72.3
%
Second Quarter 2017
273,000


3,000

 
72.3
%
Third Quarter 2017
276,000


3,000

 
72.3
%
Fourth Quarter 2017
276,000

 
3,000

 
72.3
%
Total
1,095,000





Average percentage






72.3
%

27
Table of Contents

Gasoline Crack Spread Swap Contracts
At June 30, 2017, the Company did not have any derivatives related to gasoline crack spread sales in its fuel products segment.
At December 31, 2016, the Company had the following derivatives related to gasoline crack spread sales in its fuel products segment, none of which are designated as hedges:
Gasoline Crack Spread Swap Contracts by Expiration Dates
Barrels Sold
 
BPD
 
Average Swap
($/Bbl)
First Quarter 2017
590,000

 
6,556

 
$
10.21

Total
590,000

 
 
 
 
Average price
 
 
 
 
$
10.21

Diesel Crack Spread Swap Contracts
At June 30, 2017, the Company did not have any derivatives related to diesel crack spread sales in its fuel products segment.
At December 31, 2016, the Company had the following derivatives related to diesel crack spread sales in its fuel products segment, none of which are designated as hedges:
Diesel Crack Spread Swap Contracts by Expiration Dates
Barrels Sold
 
BPD
 
Average Swap
($/Bbl)
First Quarter 2017
590,000

 
6,556

 
$
13.67

Total
590,000

 
 
 
 
Average price
 
 
 
 
$
13.67

2/1/1 Crack Spread Swap Contracts
At June 30, 2017, the Company did not have any derivatives related to 2/1/1 crack spread sales in its fuel products segment.
At December 31, 2016, the Company had the following derivatives related to 2/1/1 crack spread sales in its fuel products segment, none of which are designated as hedges:
2/1/1 Crack Spread Swap Contracts by Expiration Dates
Barrels Sold
 
BPD
 
Average Swap
($/Bbl)
First Quarter 2017
590,000

 
6,556

 
$
11.91

Total
590,000

 
 
 
 
Average price
 
 
 
 
$
11.91

9. 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.

28
Table of Contents

Recurring Fair Value Measurements
Derivative Assets and Liabilities
Derivative instruments are reported in the accompanying unaudited condensed consolidated financial statements at fair value. The Company’s commodity derivative instruments consist of over-the-counter (“OTC”) contracts, which are not traded on a public exchange. Substantially all of the Company’s commodity derivative instruments are with counterparties that have long-term credit ratings of at least Baa2 and BBB+ by Moody’s and S&P, respectively.
To estimate the fair values of the Company’s commodity derivative instruments, the Company uses the forward rate, the strike price, contractual notional amounts, the risk free rate of return and contract maturity. To estimate the fair value of the Company’s fixed-to-floating interest rate swap derivative instrument prior to settlement, the Company used discounted cash flows, which use observable inputs such as maturity and market interest rates. Various analytical tests are performed to validate the counterparty data. The fair values of the Company’s derivative instruments are adjusted for nonperformance risk and creditworthiness of the hedging entities through the Company’s credit valuation adjustment (“CVA”). The CVA is calculated at the counterparty level utilizing the fair value exposure at each payment date and applying a weighted probability of the appropriate survival and marginal default percentages. The Company uses the counterparty’s marginal default rate and the Company’s survival rate when the Company is in a net asset position at the payment date and uses the Company’s marginal default rate and the counterparty’s survival rate when the Company is in a net liability position at the payment date. As a result of applying the applicable CVA at June 30, 2017, the Company’s net assets were increased by approximately $0.2 million and net liabilities were reduced by approximately $0.2 million. As a result of applying the CVA at December 31, 2016, the Company’s net assets were increased by less than $0.1 million and net liabilities were reduced by approximately $0.5 million.
Observable inputs utilized to estimate the fair values of the Company’s derivative instruments were based primarily on inputs that are readily available in public markets or can be derived from information available in publicly quoted markets. Based on the use of various unobservable inputs, principally nonperformance risk, creditworthiness of the hedging entities and unobservable inputs in the forward rate, the Company has categorized these derivative instruments as Level 3. Significant increases (decreases) in any of those unobservable inputs in isolation would result in a significantly lower (higher) fair value measurement. The Company believes it has obtained the most accurate information available for the types of derivative instruments it holds. See Note 8 for further information on derivative instruments.
Pension Assets
Pension assets are reported at fair value in the accompanying unaudited condensed consolidated financial statements. At June 30, 2017, the Company’s investments associated with its pension plan (as such term is hereinafter defined) primarily consisted of mutual funds. The mutual funds are valued at the net asset value (“NAV”) of shares in each fund held by the pension plan at quarter end as provided by the respective investment sponsors or investment advisers. Plan investments can be redeemed within a short time frame (approximately 10 business days), if requested. See Note 10 for further information on pension assets.
Liability Awards
Unit based compensation liability awards are awards that are expected to be settled in cash on their vesting dates, rather than in equity units (“Liability Awards”). The Liability Awards are categorized as Level 1 because the fair value of the Liability Awards is based on the Company’s quoted closing unit price as of each balance sheet date.
Renewable Identification Numbers Obligation
The RINs Obligation is categorized as Level 2 and is measured at fair value using the market approach based on quoted prices from an independent pricing service. See Note 5 for further information on the Company’s RINs Obligation.

29
Table of Contents

Hierarchy of Recurring Fair Value Measurements
The Company’s recurring assets and liabilities measured at fair value at June 30, 2017, and December 31, 2016, were as follows (in millions):
 
June 30, 2017
 
December 31, 2016
 
Level 1
 
Level 2
 
Level 3
 
Total
 
Level 1
 
Level 2
 
Level 3
 
Total
Assets:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Derivative assets:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Natural gas swaps
$
—

 
$
—

 
$
(0.8
)
 
$
(0.8
)
 
$
—

 
$
—

 
$
—

 
$
—

Crude oil swaps
—

 
—

 
(0.9
)
 
(0.9
)
 
—

 
—

 
2.9

 
2.9

Crude oil percentage basis swaps
—

 
—

 
0.4

 
0.4

 
—

 
—

 
—

 
—

Crude oil basis swaps
—

 
—

 
2.3

 
2.3

 
—

 
—

 
(2.1
)
 
(2.1
)
Total derivative assets
—


—


1.0


1.0

 
—

 
—

 
0.8

 
0.8

Pension plan investments
0.1

 
—

 
—

 
0.1

 
0.3

 
—

 
—

 
0.3

Total recurring assets at fair value
$