Document
Table of Contents

 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
 
Form 10-Q
 
 
x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2016
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  x    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  x    No  ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer
 
x
  
Accelerated filer
 
¨
 
 
 
 
Non-accelerated filer
 
o  (Do not check if a smaller reporting company)
  
Smaller reporting company
 
¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  x
On August 5, 2016, there were 76,371,419 common units outstanding.
 

Table of Contents

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
QUARTERLY REPORT
For the Three and Six Months Ended June 30, 2016
Table of Contents
 
 
Page
 

2
Table of Contents

FORWARD-LOOKING STATEMENTS
This Quarterly Report on Form 10-Q (this “Quarterly Report”) includes certain “forward-looking statements.” These statements can be identified by the use of forward-looking terminology including “may,” “intend,” “believe,” “expect,” “anticipate,” “estimate,” “continue” 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 acquisitions. 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, 2015 (“2015 Annual Report”), (ii) Part II, Item 1A “Risk Factors” in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2016 (“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.




3
Table of Contents

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

 
June 30, 2016
 
December 31, 2015
 
(Unaudited)
 
 
 
(In millions, except unit data)
ASSETS
Current assets:
 
 
 
Cash and cash equivalents
$
32.2

 
$
5.6

Accounts receivable:
 
 
 
Trade
242.6

 
195.3

Other
27.6

 
15.4

 
270.2

 
210.7

Inventories
444.9


384.4

Derivative assets
4.9

 
—

Prepaid expenses and other current assets
11.5


8.3

Total current assets
763.7

 
609.0

Property, plant and equipment, net
1,705.0


1,719.2

Investment in unconsolidated affiliates
6.9


126.0

Goodwill
178.6


212.0

Other intangible assets, net
197.2


214.1

Other noncurrent assets, net
55.4


64.4

Total assets
$
2,906.8

 
$
2,944.7

LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
 
 
 
Accounts payable
$
316.2


$
316.6

Accrued interest payable
40.2


31.1

Accrued salaries, wages and benefits
13.3


32.9

Other taxes payable
21.1


17.9

Other current liabilities
144.7


119.0

Current portion of long-term debt
1.6


1.7

Note payable — related party
39.9

 
73.5

Derivative liabilities
10.4


33.9

Total current liabilities
587.4

 
626.6

Noncurrent deferred income taxes
2.0


2.1

Pension and postretirement benefit obligations
12.0


13.0

Other long-term liabilities
1.0


0.9

Long-term debt, less current portion
1,972.9


1,698.2

Total liabilities
2,575.3

 
2,340.8

Commitments and contingencies



Partners’ capital:
 
 
 
Limited partners’ interest 76,346,289 units and 75,884,400 units, issued and outstanding as of June 30, 2016, and December 31, 2015, respectively
319.3

 
578.0

General partner’s interest
18.1

 
27.5

Accumulated other comprehensive loss
(5.9
)

(1.6
)
Total partners’ capital
331.5

 
603.9

Total liabilities and partners’ capital
$
2,906.8

 
$
2,944.7

See accompanying notes to unaudited condensed consolidated financial statements.

4
Table of Contents

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2016
 
2015
 
2016
 
2015
 
(In millions, except per unit and unit data)
Sales
$
972.9

 
$
1,156.2

 
$
1,685.9

 
$
2,174.8

Cost of sales
841.6

 
953.5

 
1,468.4

 
1,776.9

Gross profit
131.3

 
202.7

 
217.5

 
397.9

Operating costs and expenses:
 
 
 
 
 
 
 
Selling
26.2

 
37.8

 
56.7

 
76.2

General and administrative
24.8

 
31.7

 
52.4

 
70.9

Transportation
45.0

 
42.3

 
84.2

 
84.3

Taxes other than income taxes
4.2

 
4.0

 
9.9

 
8.0

Asset impairment
33.4

 
—

 
33.4

 
—

Other
0.3

 
3.2

 
2.3

 
6.1

Operating income (loss)
(2.6
)
 
83.7

 
(21.4
)
 
152.4

Other income (expense):
 
 
 
 
 
 
 
Interest expense
(42.8
)
 
(27.4
)
 
(73.1
)
 
(54.4
)
Debt extinguishment costs
—

 
(46.6
)
 
—

 
(46.6
)
Realized loss on derivative instruments
(6.0
)
 
(14.0
)
 
(18.3
)
 
(5.1
)
Unrealized gain (loss) on derivative instruments
23.8

 
5.2

 
28.4

 
(22.7
)
Loss from unconsolidated affiliates
(7.1
)
 
(8.2
)
 
(18.2
)
 
(12.7
)
Loss on sale of unconsolidated affiliates
(113.4
)

—


(113.4
)

—

Other
0.5

 
0.7

 
0.9

 
1.5

Total other expense
(145.0
)
 
(90.3
)
 
(193.7
)
 
(140.0
)
Net income (loss) before income taxes
(147.6
)
 
(6.6
)
 
(215.1
)
 
12.4

Income tax expense (benefit)
0.3

 
(9.1
)
 
0.5

 
(13.9
)
Net income (loss)
$
(147.9
)
 
$
2.5

 
$
(215.6
)
 
$
26.3

Allocation of net income (loss):
 
 
 
 
 
 
 
Net income (loss)
$
(147.9
)
 
$
2.5

 
$
(215.6
)
 
$
26.3

Less:
 
 
 
 
 
 
 
General partner’s interest in net income (loss)
(2.9
)
 
—

 
(4.3
)
 
0.5

General partner’s incentive distribution rights
—

 
4.2

 
—

 
8.4

Net income (loss) available to limited partners
$
(145.0
)
 
$
(1.7
)
 
$
(211.3
)
 
$
17.4

Weighted average limited partner units outstanding:
 
 
 
 
 
 
 
Basic
76,761,504

 
76,092,517

 
76,491,775

 
73,675,251

Diluted
76,761,504

 
76,092,517

 
76,491,775

 
73,730,189

Limited partners’ interest basic and diluted net income (loss) per unit
$
(1.89
)
 
$
(0.02
)
 
$
(2.76
)
 
$
0.23

Cash distributions declared per limited partner unit
$
—

 
$
0.685

 
$
0.685

 
$
1.37

See accompanying notes to unaudited condensed consolidated financial statements.


5
Table of Contents

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2016
 
2015
 
2016
 
2015
 
(In millions)
Net income (loss)
$
(147.9
)
 
$
2.5

 
$
(215.6
)
 
$
26.3

Other comprehensive income (loss):
 
 
 
 
 
 
 
Cash flow hedges:
 
 
 
 
 
 
 
Cash flow hedge gain reclassified to net income (loss)
(2.3
)
 
(11.5
)
 
(4.4
)
 
(9.8
)
Change in fair value of cash flow hedges
—

 
(1.1
)
 
—

 
(6.2
)
Defined benefit pension and retiree health benefit plans
0.1

 
0.1

 
0.1

 
0.3

Foreign currency translation adjustment
—

 
—

 
—

 
(0.3
)
Total other comprehensive loss
(2.2
)
 
(12.5
)
 
(4.3
)
 
(16.0
)
Comprehensive income (loss) attributable to partners’ capital
$
(150.1
)
 
$
(10.0
)
 
$
(219.9
)
 
$
10.3

See accompanying notes to unaudited condensed consolidated financial statements.


6
Table of Contents

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
 
 
Accumulated Other
Comprehensive Loss
 
Partners’ Capital
 
 
 
 
General
Partner
 
Limited
Partners
 
Total
 
(In millions)
Balance at December 31, 2015
$
(1.6
)
 
$
27.5

 
$
578.0

 
$
603.9

Other comprehensive loss
(4.3
)
 
—

 
—

 
(4.3
)
Net loss
—

 
(4.3
)
 
(211.3
)
 
(215.6
)
Amortization of vested phantom units
—

 
—

 
2.9

 
2.9

Issuances of phantom units
—

 
—

 
4.1

 
4.1

Settlement of tax withholdings on equity-based incentive compensation
—

 
—

 
(2.3
)
 
(2.3
)
Contributions from Calumet GP, LLC
—

 
0.2

 
—

 
0.2

Distributions to partners
—

 
(5.3
)
 
(52.1
)
 
(57.4
)
Balance at June 30, 2016
$
(5.9
)
 
$
18.1

 
$
319.3

 
$
331.5

See accompanying notes to unaudited condensed consolidated financial statements.


7
Table of Contents

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
 
Six Months Ended June 30,
 
2016

2015
 
(In millions)
Operating activities
 
 
 
Net income (loss)
$
(215.6
)

$
26.3

Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
 
 
Depreciation and amortization
82.6


71.4

Amortization of turnaround costs
17.4


12.7

Non-cash interest expense
4.6


2.9

Non-cash debt extinguishment costs
—

 
9.1

Provision for doubtful accounts
0.5


0.2

Unrealized (gain) loss on derivative instruments
(28.4
)

22.7

Asset impairment
33.4

 
—

(Gain) loss on disposal of fixed assets
(0.7
)
 
1.0

Non-cash equity based compensation
2.9


5.5

Deferred income tax benefit
(0.2
)
 
(14.1
)
Lower of cost or market inventory adjustment
(44.4
)
 
0.8

Loss from unconsolidated affiliates
18.2

 
12.7

Loss on sale of unconsolidated affiliates
113.4

 
—

Other non-cash activities
2.3


2.9

Changes in assets and liabilities:
 
 
 
Accounts receivable
(60.0
)

39.4

Inventories
(10.3
)

(40.6
)
Prepaid expenses and other current assets
(1.5
)

4.5

Derivative activity
(10.4
)

(3.5
)
Turnaround costs
(8.1
)

(5.9
)
Other assets
(0.4
)
 
—

Accounts payable
35.1


(7.0
)
Accrued interest payable
9.1


(5.1
)
Accrued salaries, wages and benefits
(16.0
)

1.6

Other taxes payable
3.2


1.3

Other liabilities
22.5


21.7

Pension and postretirement benefit obligations
(0.9
)

(0.5
)
Net cash provided by (used in) operating activities
(51.7
)
 
160.0

Investing activities
 
 
 
Additions to property, plant and equipment
(87.9
)

(153.2
)
Investment in unconsolidated affiliates
(41.8
)

(46.0
)
Proceeds from sale of unconsolidated affiliates
29.0

 
—

Proceeds from sale of property, plant and equipment
1.9

 
0.2

Net cash used in investing activities
(98.8
)
 
(199.0
)
Financing activities
 
 
 
Proceeds from borrowings — revolving credit facility
479.0


637.3

Repayments of borrowings — revolving credit facility
(589.9
)

(685.0
)
Repayments of borrowings — senior notes
—

 
(275.0
)
Repayments of borrowings — related party note
(34.5
)
 
—

Payments on capital lease obligations
(4.1
)

(3.5
)
Proceeds from other financing obligations
2.4

 
—

Proceeds from senior notes offering
393.1


322.6

Debt issuance costs
(9.9
)

(5.6
)
Proceeds from public offerings of common units, net
—


161.5

Contributions from Calumet GP, LLC
0.2


3.5

Common units repurchased and taxes paid for phantom unit grants
(1.8
)

(3.6
)
Distributions to partners
(57.4
)

(110.0
)
Net cash provided by financing activities
177.1

 
42.2

Net increase in cash and cash equivalents
26.6

 
3.2

Cash and cash equivalents at beginning of period
5.6


8.5

Cash and cash equivalents at end of period
$
32.2

 
$
11.7

Supplemental disclosure of non-cash financing and investing activities
 
 
 
Non-cash property, plant and equipment additions
$
20.5

 
$
61.9

See accompanying notes to unaudited condensed consolidated financial statements.

8
Table of Contents

CALUMET SPECIALTY PRODUCTS PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
1. Description of the Business
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, 2016, the Company had 76,346,289 limited partner common units and 1,558,087 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, 2016, and for the three and six months ended June 30, 2016 and 2015, included herein have been prepared, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). Certain information and disclosures normally included in the consolidated financial statements prepared in accordance with generally accepted accounting principles (“GAAP”) in the U.S. have been condensed or omitted pursuant to such rules and regulations, although the Company believes that the following disclosures are adequate to make the information presented not misleading. These unaudited condensed consolidated financial statements reflect all adjustments that, in the opinion of management, are necessary to present fairly the results of operations for the interim periods presented. All adjustments are of a normal nature, unless otherwise disclosed. The results of operations for the three and six months ended June 30, 2016, are not necessarily indicative of the results that may be expected for the year ending December 31, 2016. These unaudited condensed consolidated financial statements should be read in conjunction with the Company’s 2015 Annual Report.
2. Summary of Significant Accounting Policies
Reclassifications
Certain amounts in the prior years’ condensed consolidated financial statements have been reclassified to conform to the current year presentation.
Other Current Liabilities
Other current liabilities consisted of the following at June 30, 2016 and December 31, 2015 (in millions):
 
June 30, 2016
 
December 31, 2015
RINs Obligation
$
114.7

 
$
88.4

Other
30.0

 
30.6

Total
$
144.7

 
$
119.0

The Company’s RINs obligation (“RINs Obligation”) represents a liability for the purchase of RINs to satisfy the U.S. EPA requirement to blend biofuels into the fuel products it produces pursuant to the EPA’s RFS. RINs are assigned to biofuels produced in the U.S. as required by the EPA. The EPA sets annual quotas for the percentage of biofuels that must be blended into transportation fuels consumed in the U.S. and, as a producer of motor fuels from petroleum, the Company is required to blend biofuels into the fuel products it produces at a rate that will meet the EPA’s annual quota. To the extent the Company is unable to blend biofuels at that rate, it must purchase RINs in the open market to satisfy the annual requirement. The Company’s RINs Obligation is based on the amount of RINs it must purchase and the price of those RINs as of the balance sheet date. The Company uses the inventory model to account for RINs, measuring acquired RINs at weighted-average cost. The cost of RINs used each period is charged to cost of sales with cash inflows and outflows recorded in the operating cash flow section of the unaudited condensed consolidated statements of cash flows. Excess RINs are classified as inventory in the condensed consolidated balance sheets. The Company recognizes a liability at the end of each reporting period in which the Company does not have sufficient RINs to cover the RINs Obligation. The liability is calculated by multiplying the RINs shortage (based on actual results) by the period end RIN spot price.
From time to time, the Company holds varying amounts of RINs for resale. RINs obtained from third parties are initially recorded at their cost at the time the Company acquires them and are subsequently revalued at the lower of cost or market as of the last day of each accounting period and the resulting adjustments are reflected in costs of goods sold for the period. The value of RINs obtained from third parties would be reflected in prepaid expenses and other assets on the consolidated balance sheets.

9
Table of Contents

New Accounting Pronouncements
In March 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-09, Compensation — Stock Compensation (Topic 606): Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”). ASU 2016-09 involves several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. Under the new standard, income tax benefits and deficiencies are to be recognized as income tax expense or benefit in the income statement and the tax effects of exercised or vested awards should be treated as discrete items in the reporting period in which they occur. Excess tax benefits should be classified along with other income tax cash flows as an operating activity. In regards to forfeitures, the entity may make an entity-wide accounting policy election to either estimate the number of awards that are expected to vest or account for forfeitures when they occur. The amendments in this standard are effective for fiscal years (including interim periods) beginning after December 15, 2016, with early adoption permitted. The adoption of ASU 2016-09 is not expected to have an impact on the Company’s condensed consolidated financial statements.
In March 2016, the FASB issued ASU No. 2016-07, Investments — Equity Method and Joint Ventures (Topic 323): Simplifying the Transition to the Equity Method of Accounting (“ASU 2016-07”), which eliminates the retroactive adjustments to an investment upon it qualifying for the equity method of accounting as a result of an increase in the level of ownership interest or degree of influence by the investor. ASU 2016-07 requires that the equity method investor add the cost of acquiring the additional interest in the investee to the current basis of the investor’s previously held interest and adopt the equity method of accounting as of the date the investment qualifies for equity method accounting. The amendments in this standard are effective for fiscal years (including interim periods) beginning after December 15, 2016, with early adoption permitted. The adoption of ASU 2016-07 is not expected to have an impact on the Company’s condensed consolidated financial statements.
In March 2016, the FASB issued ASU No. 2016-06, Derivatives and Hedging (Topic 815): Contingent Put and Call Options in Debt Instruments (“ASU 2016-06”). ASU 2016-06 simplifies the embedded derivative analysis for debt instruments containing contingent call or put options by removing the requirement to assess whether a contingent event is related to interest rates or credit risks. The amendments in this standard are effective for fiscal years (including interim periods) beginning after December 15, 2016, with early adoption permitted. The adoption of ASU 2016-06 is not expected to have an impact on the Company’s condensed consolidated financial statements.
In March 2016, the FASB issued ASU No. 2016-05, Derivatives and Hedging (Topic 815): Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships (“ASU 2016-05”). ASU 2016-05 clarifies that a change in the counterparty to a derivative instrument that has been designated as a hedging instrument under Topic 815 does not, in and of itself, require dedesignation of that hedging relationship provided that all other hedge accounting criteria continue to be met. The amendments in this standard are effective for fiscal years (including interim periods) beginning after December 15, 2016, with early adoption permitted. An entity can elect to adopt the amendments of ASU 2016-05 on either a prospective or modified retrospective basis. The adoption of ASU 2016-05 is not expected to have an impact on the Company’s condensed consolidated financial statements.
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which supersedes the lease accounting requirements in Accounting Standards Codification (“ASC”) Topic 840, Leases. ASU 2016-02 provides principles for the recognition, measurement, presentation and disclosure of leases for both lessees and lessors. The new standard requires lessees to apply a dual approach, classifying leases as either finance or operating leases based on the principle of whether or not the lease is effectively a financed purchase by the lessee. This classification will determine whether lease expense is recognized based on an effective interest method or on a straight-line basis over the term of the lease, respectively. A lessee is also required to record a right-of-use asset and a lease liability for all leases with a term of greater than twelve months regardless of classification. Leases with a term of twelve months or less will be accounted for similar to existing guidance for operating leases. The amendments in this standard are effective for fiscal years (including interim periods) beginning after December 15, 2018, with early adoption permitted and modified retrospective application required. The Company is currently evaluating the impact of this standard on its condensed consolidated financial statements.
In January 2016, the FASB issued ASU No. 2016-01, Financial Instruments — Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities (“ASU 2016-01”). ASU 2016-01 requires that (i) equity investments in unconsolidated entities that are not accounted for under the equity method of accounting generally be measured at fair value with changes recognized in net income (loss) and (ii) when the fair value option has been elected for financial liabilities, changes in fair value due to instrument-specific credit risk be recognized separately in other comprehensive income (loss). Additionally, ASU 2016-01 changes the presentation and disclosure requirements for financial instruments. The amendments in this standard are effective for fiscal years (including interim periods) beginning after December 15, 2017, with early adoption not permitted. The Company is currently evaluating the impact of this standard on its condensed consolidated financial statements.
In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”), which supersedes the revenue recognition requirements in ASC Topic 605, Revenue Recognition. ASU 2014-09 is based on the principle that revenue is recognized to depict the transfer of goods or services to customers in an amount that reflects the

10
Table of Contents

consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts, including significant judgments and changes in judgments and assets recognized from costs incurred to obtain or fulfill a contract. ASU 2014-09 was originally effective for fiscal years (including interim periods) beginning after December 15, 2016. In August 2015, the FASB issued ASU No. 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date, which defers the effective date by one year, with early adoption permitted as of the original effective date. ASU 2014-09 allows for either a full retrospective or a modified retrospective transition method. In March 2016, the FASB issued ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606) — Principal versus Agent Considerations (“ASU 2016-08”). ASU 2016-08 provides clarifying guidance regarding the application of ASU 2014-09 when another party, along with the reporting entity, is involved in providing a good or a service to a customer. In these circumstances, an entity is required to determine whether the nature of its promise is to provide that good or service to the customer (that is, the entity is a principal) or to arrange for the good or service to be provided to the customer by the other party (that is, the entity is an agent). ASU 2016-08 clarifies the implementation guidance on principal versus agent considerations. In April 2016, the FASB issued ASU No. 2016-10, Revenue from Contracts with Customers (Topic 606) — Identifying Performance Obligations and Licensing (“ASU 2016-10”). ASU 2016-10 further amends the guidance with respect to certain implementation issues on identifying performance obligations and accounting for licenses of intellectual property. In May 2016, the FASB issued ASU No. 2016-11, Revenue Recognition (Topic 605) and Derivatives and Hedging (Topic 815) — Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16 Pursuant to Staff Announcements at the March 3, 2016, EITF Meeting (“ASU 2016-11”). The amendments in ASU 2016-11 rescinded certain SEC Staff Observer comments that are codified, effective upon the adoption of ASU 2014-09. In May 2016, the FASB issued ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606) — Narrow-Scope Improvements and Practical Expedients (“ASU 2016-12”). The amendments in ASU 2016-12 address certain issues identified in the guidance on assessing collectibility, presentation of sales taxes, non-cash consideration and completed contracts and contract modifications at transition. Companies are permitted to either apply the requirements retrospectively to all prior periods presented or apply the requirements in the year of adoption through a cumulative adjustment. The amendments in these standards, along with ASU 2014-09, are effective for fiscal years (including interim periods) beginning after December 15, 2017. The Company is currently evaluating the impact of these standards on its condensed consolidated financial statements.
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 $62.5 million and $41.0 million lower as of June 30, 2016, and December 31, 2015, respectively.
Inventories consist of the following (in millions):
 
June 30, 2016
 
December 31, 2015
Raw materials
$
64.2

 
$
47.9

Work in process
76.1

 
64.0

Finished goods
304.6

 
272.5

 
$
444.9

 
$
384.4

Under the LIFO method, the most recently incurred costs are charged to cost of sales and inventories are valued at the earliest acquisition costs. In addition, the use of the LIFO inventory method may result in increases or decreases to cost of sales in years that inventory volumes decline as the result of charging cost of sales with LIFO inventory costs generated in prior periods. In periods of rapidly declining prices, LIFO inventories may have to be written down to market value due to the higher costs assigned to LIFO layers in prior periods. Such write downs are subject to reversal in subsequent periods, not to exceed LIFO cost, if prices recover. During the three months ended June 30, 2016 and 2015, the Company recorded $36.3 million and $12.4 million of gains, respectively, in cost of sales in the condensed consolidated statements of operations due to the lower of cost or market (“LCM”) valuation. During the six months ended June 30, 2016 and 2015, the Company recorded $44.4 million of gains and $0.8 million of losses, respectively, in cost of sales in the condensed consolidated statements of operations due to the LCM valuation.

11
Table of Contents

4. Investment in Unconsolidated Affiliates
The following table summarizes the Company’s investments in unconsolidated affiliates as of June 30, 2016, and December 31, 2015 (in millions):
 
June 30, 2016
 
December 31, 2015
 
Investment
 
Percent Ownership
 
Investment
 
Percent Ownership
Dakota Prairie Refining, LLC
$
—

 
—
%
 
$
124.7

 
50.0
%
Pacific New Investment Limited
5.9

 
13.8
%
 
—

 
—
%
Other
1.0

 
 
 
1.3

 
 
Total
$
6.9

 
 
 
$
126.0

 
 
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 three and six months ended June 30, 2016.
The following represents summary financial information for Dakota Prairie, presented at 100% (in millions):
 
Three Months Ended June 27,
 
Three Months Ended June 30,
 
Six Months Ended June 27,
 
Six Months Ended June 30,
 
2016
 
2015
 
2016
 
2015
Operating revenue
$
74.3

 
$
48.4

 
$
119.4

 
$
50.1

Operating loss
$
(12.7
)
 
$
(14.8
)
 
$
(33.5
)
 
$
(21.8
)
Net loss
$
(13.6
)
 
$
(15.2
)
 
$
(35.2
)
 
$
(22.3
)
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 expects to invest $10.0 million in cash and provide a technology license in exchange for an equity interest of approximately 10% in Hi-Speed through its ownership of 23.8% in PACNIL.
The Company accounts for its ownership in PACNIL under the equity method of accounting. As of June 30, 2016, the Company had an investment of $5.9 million in PACNIL, primarily related to the purchase of equity in the Hi-Speed joint venture.
5. Goodwill
In April 2016, Calumet GP, LLC’s Board of Directors determined to suspend payment of the Company’s quarterly cash distribution. The suspension of the quarterly cash distribution caused a sustained decrease in the Company’s common unit price. As a result, the Company determined that these recent events constituted a triggering event that required the Company to update its financial projections and its goodwill impairment assessment as of April 30, 2016. An impairment charge of $33.4 million for goodwill related to the fuels segment has been recorded in the unaudited condensed consolidated statements of operations within asset impairment. The impairment charge was primarily driven by the reduced outlook on revenues and profitability as a result of falling crude oil prices and crack spreads.

12
Table of Contents

To derive the fair value of the reporting units, as required in step one of the impairment test, the Company used the income approach, specifically the discounted cash flow method, to determine the fair value of each reporting unit and the associated amount of the impairment charge. The income approach focuses on the income-producing capability of an asset, measuring the current value of the asset by calculating the present value of its future economic benefits such as cash earnings, cost savings, corporate tax structure and product offerings. Value indications are developed by discounting expected cash flows to their present value at a rate of return that incorporates the risk-free rate for the use of funds, the expected rate of inflation, and risks associated with the reporting unit.
Inputs used to estimate the fair value of the Company’s reporting units are considered Level 3 inputs of the fair value hierarchy and include the following:
•
The Company’s financial projections for its reporting units are based on its analysis of various supply and demand factors which include, among other things, industry-wide capacity, its planned utilization rate, end-user demand, crack spreads, capital expenditures and economic conditions. Such estimates are consistent with those used in the Company’s planning and capital investment reviews and include recent historical prices and published forward prices. Revenue growth rates assumed for the Company’s Great Falls reporting unit where impairment was recognized were approximately 41.1% for 2016 and (2.6)% to 39.9% for 2017 and beyond. Revenue growth rates assumed for the Company’s San Antonio reporting unit where impairment was recognized were approximately (8.5)% for 2016 and (1.0)% to 27.4%, respectively, for 2017 and beyond.

•
The discount rate used to measure the present value of the projected future cash flows is based on a variety of factors, including market and economic conditions, operational risk, regulatory risk and political risk. This discount rate is also compared to recent observable market transactions, if possible. The discount rate used for the Company’s Great Falls and San Antonio reporting units where impairment was recognized were approximately 13.0% and 13.5%, respectively, per year.
For Level 3 measurements, significant increases or decreases in long-term growth rates or discount rates in isolation or in combination could result in a significantly lower or higher fair value measurement.
Changes in goodwill balances for the periods indicated below are as follows (in millions):
 
Specialty
Products
 
Fuel
Products
 
Oilfield
Services
 
Total
 
 
 
 
Net balance as of December 31, 2014
$
173.5

 
$
38.5

 
$
33.8

 
$
245.8

Impairment (1)
—

 
—

 
(33.8
)
 
(33.8
)
Net balance as of December 31, 2015
$
173.5

 
$
38.5

 
$
—

 
$
212.0

Impairment (1)
—

 
(33.4
)
 
—

 
(33.4
)
Net balance as of June 30, 2016
$
173.5

 
$
5.1

 
$
—

 
$
178.6

(1) 
Total accumulated goodwill impairment as of June 30, 2016, and December 31, 2015, is $103.2 million and $69.8 million, respectively.
6. Commitments and Contingencies
From time to time, the Company is a party to certain claims and litigation incidental to its business, including claims made by various regulatory and taxation authorities, such as the EPA, various state environmental regulatory bodies, the Internal Revenue Service, various state and local departments of revenue and the federal Occupational Safety and Health Administration (“OSHA”), as the result of audits or reviews of the Company’s business. In addition, the Company has property, business interruption, general liability and various other insurance policies that may result in certain losses or expenditures being reimbursed to the Company.
Environmental
The Company conducts crude oil and specialty hydrocarbon refining, blending and terminal operations in addition to providing oilfield services and products, which activities are subject to stringent federal, state, regional and local laws and regulations governing worker health and safety, the discharge of materials into the environment and environmental protection. These laws and regulations impose obligations that are applicable to the Company’s operations, such as requiring the acquisition of permits to conduct regulated activities, restricting the manner in which the Company may release materials into the environment, requiring remedial activities or capital expenditures to mitigate pollution from former or current operations, requiring the application of specific health and safety criteria addressing worker protection and imposing substantial liabilities for pollution resulting from its operations. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil and criminal penalties; the imposition of investigatory, remedial or corrective action obligations or the incurrence of capital

13
Table of Contents

expenditures; the occurrence of delays in the permitting, development or expansion of projects, and the issuance of injunctive relief limiting or prohibiting Company activities. Moreover, certain of these laws impose joint and several, strict liability for costs required to remediate and restore sites where petroleum hydrocarbons, wastes or other materials have been released or disposed. In addition, new laws and regulations, new interpretations of existing laws and regulations, increased governmental enforcement or other developments, some of which legal requirements are discussed below, could significantly increase the Company’s operational or compliance expenditures.
Remediation of subsurface contamination is in process at certain of the Company’s refinery sites and is being overseen by the appropriate state agencies. Based on current investigative and remedial activities, the Company believes that the soil and groundwater contamination at these refineries can be controlled or remedied without having a material adverse effect on the Company’s financial condition. However, such costs are often unpredictable and, therefore, there can be no assurance that the future costs will not become material.
San Antonio Refinery
In connection with the acquisition of the San Antonio refinery, the Company agreed to indemnify NuStar for an unlimited term and without consideration of a monetary deductible or cap from any environmental liabilities associated with the San Antonio refinery, except for any governmental penalties or fines that may result from NuStar’s actions or inactions during NuStar’s 20-month period of ownership of the San Antonio refinery. Anadarko Petroleum Corporation (“Anadarko”) and Age Refining, Inc. (“Age Refining”), a third party that has since entered bankruptcy, are subject to a 1995 Agreed Order from the Texas Natural Resource Conservation Commission, now known as the Texas Commission on Environmental Quality, pursuant to which Anadarko and Age Refining are obligated to assess and remediate certain contamination at the San Antonio refinery that predates the Company’s acquisition of the facility. The Company does not expect this pre-existing contamination at the San Antonio refinery to have a material adverse effect on its financial position or results of operations.
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 expenses totaled approximately $18.5 million as of June 30, 2016, of which $14.6 million was capitalized into the cost of the Company’s recently completed expansion project and $3.9 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 granted Holly’s motion to dismiss the case and ordered that all of the claims be addressed in arbitration. In the event the Company is unsuccessful, the Company will be responsible for the remediation expenses. The Company expects that it may incur some costs to remediate other environmental conditions at the Great Falls refinery; however, the Company believes at this time that these other costs it may incur will not be material to its financial position or results of operations.
Superior Refinery
In connection with the acquisition of the Superior refinery, the Company became a party to an existing Refinery Initiative Consent Decree (“Superior Consent Decree”) with the EPA and the Wisconsin Department of Natural Resources (“WDNR”) that applies, in part, to its Superior refinery. Under the Superior Consent Decree, the Company must complete certain reductions in air emissions at the Superior refinery as well as report upon certain emissions from the refinery to the EPA and the WDNR. As of June 30, 2016, the Company estimates costs of up to $4.0 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

14
Table of Contents

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, 2016 and 2015, the Company incurred less than $0.1 million for costs related to installing process equipment at the Superior refinery pursuant to EPA fuel content regulations.
On June 29, 2012, the EPA issued a Finding of Violation/Notice of Violation to the Superior refinery, which included a proposed penalty amount of $0.1 million. This finding is in response to information provided to the EPA by the Company in response to an information request. The EPA alleges that the efficiency of the flares at the Superior refinery is lower than regulatory requirements. The Company is contesting the allegations and is in settlement discussions with the EPA to resolve this issue. The Company has not yet received formal action from the EPA. The Company does not believe that the resolution of these allegations will have a material adverse effect on 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 acquisition of the Superior refinery.
Shreveport, Cotton Valley and Princeton Refineries
On December 23, 2010, the Company entered into a settlement agreement with the Louisiana Department of Environmental Quality (“LDEQ”) under LDEQ’s “Small Refinery and Single Site Refinery Initiative,” covering the Shreveport, Princeton and Cotton Valley refineries. This settlement agreement became effective on January 31, 2012. The settlement agreement, termed the “Global Settlement,” resolved alleged violations of the federal Clean Air Act and federal Clean Water Act regulations that arose prior to December 23, 2010. Among other things, the Company agreed to complete beneficial environmental programs and implement emissions reduction projects at the Company’s Shreveport, Cotton Valley and Princeton refineries on an agreed-upon schedule. During the three months ended June 30, 2016, the Company incurred no such expenditures. During the three months ended June 30, 2015, the Company incurred approximately $1.4 million of such expenditures. During the six months ended June 30, 2016 and 2015, the Company incurred approximately $0.4 million and $2.4 million, respectively, of such expenditures and estimates additional expenditures of approximately $3.0 million to $5.0 million of capital expenditures and expenditures related to additional personnel and environmental studies through 2016 as a result of the implementation of these requirements. These capital investment requirements are incorporated into the Company’s annual capital expenditures budget and the Company does not expect any additional capital expenditures as a result of the required audits or required operational changes included in the Global Settlement to have a material adverse effect on the Company’s financial position or results of operations.
The Company is contractually indemnified by Shell Oil Company (“Shell”), as successor to Pennzoil-Quaker State Company, and Atlas Processing Company, under an asset purchase agreement between the Company and Shell, for specified environmental liabilities arising from the operations of the Shreveport refinery prior to the Company’s acquisition of the facility. The Company believes the contractual indemnity is unlimited in amount and duration, but requires the Company to contribute $1.0 million of the first $5.0 million of indemnified costs for certain of the specified environmental liabilities.
Bel-Ray Facility
Bel-Ray executed an Administrative Consent Order (“ACO”) with the New Jersey Department of Environmental Protection, effective January 4, 1994, which required investigation and remediation of contamination at or emanating from the Bel-Ray facility. In 2000, Bel-Ray entered into a fixed price remediation contract with Weston Solutions (“Weston”), a large remediation contractor, whereby Weston agreed to be fully liable for the remediation of the soil and groundwater issues at the facility, including an offsite groundwater plume pursuant to the ACO (“Weston Agreement”). The Weston Agreement set up a trust fund to reimburse Weston, administered by Bel-Ray’s environmental counsel. As of June 30, 2016, the trust fund contained approximately $0.8 million. In addition, Weston has remediation cost containment insurance, should Weston be unable to complete the work required under the Weston Agreement. In connection with the acquisition of Bel-Ray, the Company became a party to the Weston Agreement.

15
Table of Contents

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
The Company’s 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 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 net of amounts internally generated or purchased and the price of those RINs as of the balance sheet date.
On June 28, 2016, the EPA granted certain of the Company’s refineries a “small refinery exemption” under the RFS for the full year 2014, as provided for under the Clean Air Act. In granting those exemptions, the EPA determined that for the full year 2014, compliance with the RFS would represent a “disproportionate economic hardship” for these refineries.
As of June 30, 2016, the Company had a RINs Obligation of $114.7 million. RINs expense for the three and six months ended June 30, 2016, was $8.2 million and $25.0 million, respectively. As of June 30, 2015, the Company had a RINs Obligation of $41.5 million. RINs gain for the three and six months ended June 30, 2015, was $9.6 million and $2.3 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 ensure compliance with applicable laws and regulations. The Company conducts periodic audits of Process Safety Management (“PSM”) systems at each of its locations subject to the PSM standard. The Company’s compliance with applicable health and safety laws and regulations has required, and continues to require, substantial expenditures. Changes in occupational safety and health laws and regulations or a finding of non-compliance with current laws and regulations could result in additional capital expenditures or operating expenses, as well as civil penalties and, in the event of a serious injury or fatality, criminal charges.
The Company has completed studies to assess the adequacy of its PSM practices at its Shreveport refinery with respect to certain consensus codes and standards. During the three months ended June 30, 2016, the Company incurred no PSM related capital expenditures. During the three months ended June 30, 2015, the Company incurred $0.2 million of PSM related capital expenditures. During the six months ended June 30, 2016 and 2015, the Company incurred $0.3 million and $0.3 million, respectively, of related capital expenditures and expects to incur up to an additional $1.0 million during 2016 to address OSHA compliance issues identified in these studies. The Company expects these capital expenditures will enhance its equipment such that the equipment maintains compliance with applicable consensus codes and standards.
In the first quarter of 2011, OSHA conducted an inspection of the Cotton Valley refinery’s PSM program. On March 14, 2011, OSHA issued a Citation and Notification of Penalty (the “Cotton Valley Citation”) to the Company as a result of the Cotton Valley inspection, which included a proposed penalty amount of $0.2 million. The Company has contested the Cotton Valley Citation and the parties have reached a tentative settlement with OSHA on the matter, which the Company does not believe will have a material adverse effect on its financial position or results of operations.
Labor Matters
The Company has employees covered by various collective bargaining agreements. The Company’s Cotton Valley facility collective bargaining agreement was ratified on April 1, 2016, and will expire on March 31, 2019. The Dickinson facility collective bargaining agreement was ratified on April 1, 2016, and will expire on March 31, 2019. The Missouri esters facility collective bargaining agreement was ratified on May 1, 2016, and will expire on April 30, 2017. The Shreveport refinery collective bargaining agreement was extended on May 1, 2016, until a new agreement is reached or is voided by either party with a 30-day written notice.

16
Table of Contents

Legal Proceedings
The Company is subject to claims and litigation arising in the normal course of its business. The Company has recorded accruals with respect to certain of these matters, where appropriate, that are reflected in the condensed consolidated financial statements but are not, individually or in the aggregate, considered material. For other matters, the Company has not recorded accruals because it has not yet determined that a loss is probable or because the amount of loss cannot be reasonably estimated. While the ultimate outcome of claims and litigation currently pending cannot be determined, the Company currently does not expect that these proceedings and claims, individually or in the aggregate, will have a material adverse effect on its financial position, results of operations or cash flows. The outcome of any litigation is inherently uncertain, however, and if decided adversely to the Company, or if the Company determines that settlement of particular litigation is appropriate, the Company may be subject to liability that could have a material adverse effect on its financial position, results of operations or cash flows.
Standby Letters of Credit
The Company has agreements with various financial institutions for standby letters of credit which have been issued primarily to vendors. As of June 30, 2016 and December 31, 2015, the Company had outstanding standby letters of credit of $64.4 million and $66.8 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, 2016 and December 31, 2015, the maximum amount of letters of credit the Company could issue under its revolving credit facility was subject to borrowing base limitations, with a maximum letter of credit sublimit equal to $600.0 million, which amount may be increased to 90% of revolver commitments in effect ($1.0 billion at June 30, 2016, and December 31, 2015) with the consent of the Agent (as defined below).
As of June 30, 2016 and December 31, 2015, the Company had availability to issue letters of credit of $437.5 million and $233.5 million, respectively, under its revolving credit facility.
7. Long-Term Debt
Long-term debt consisted of the following (in millions):
 
June 30, 2016
 
December 31, 2015
Borrowings under amended and restated senior secured revolving credit agreement with third-party lenders, interest payments quarterly, borrowings due July 2019, weighted average interest rate of 3.7% at June 30, 2016
$
0.1

 
$
111.0

Borrowings under 2021 Secured Notes, interest at a fixed rate of 11.50%, interest payments semiannually, borrowings due January 2021, effective interest rate of 12.1% for the six months ended June 30, 2016
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, 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, 2016 (1)
352.7

 
352.9

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

 
325.0

Related party note payable, interest at a fixed rate of 6.0% on a portion of the note, interest payments at various dates, borrowings due July 2016, weighted average interest rate of 6.0% for the six months ended June 30, 2016
39.9

 
73.5

Capital lease obligations, at various interest rates, interest and principal payments monthly through October 2034
45.6

 
46.4

Less unamortized debt issuance costs (2)
(36.0
)
 
(28.9
)
Less unamortized discounts
(12.9
)
 
(6.5
)
Total long-term debt
2,014.4

 
1,773.4

Less current portion of note payable — related party
39.9

 
73.5

Less current portion of long-term debt
1.6

 
1.7

 
$
1,972.9

 
$
1,698.2

 

17
Table of Contents

(1) 
The balance includes a fair value interest rate hedge adjustment, which increased the debt balance by $2.7 million and $2.9 million as of June 30, 2016, and December 31, 2015, 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 $10.9 million and $8.1 million at June 30, 2016, and December 31, 2015, 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 $383.2 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.
At any time prior to April 15, 2018, the Company may on any one or more occasions redeem up to 35% of the aggregate principal amount of the 2021 Secured Notes with the net proceeds of a public or private equity offering at a redemption price of 111.5% of the principal amount, plus any accrued and unpaid interest to the date of redemption, provided that: (1) at least 65% of the aggregate principal amount of 2021 Secured Notes issued remains outstanding immediately after the occurrence of such redemption and (2) the redemption occurs within 180 days of the date of the closing of such public or private equity offering.
On and after April 15, 2018, the Company may on any one or more occasions redeem all or a part of the 2021 Secured Notes at the redemption prices (expressed as percentages of principal amount) set forth below, plus any accrued and unpaid interest to the applicable redemption date on such 2021 Secured Notes, if redeemed during the twelve-month period beginning on April 15 of the years indicated below: 
Year
 
Percentage
2018
 
111.500
%
2019
 
108.625
%
2020 and thereafter
 
100.000
%
Prior to April 15, 2018, the Company may on any one or more occasions redeem all or part of the 2021 Secured Notes at a redemption price equal to the sum of: (1) the principal amount thereof, plus (2) a make-whole premium (as set forth in the indenture governing the 2021 Secured Notes) at the redemption date, plus any accrued and unpaid interest to the applicable redemption date.
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.
On March 27, 2015, in connection with the issuance and sale of the 2023 Notes, the Company entered into a registration rights agreement with the initial purchasers of the 2023 Notes obligating the Company to use reasonable best efforts to file an exchange offer registration statement with the SEC, so that holders of the 2023 Notes can offer to exchange the 2023 Notes for registered notes having substantially the same terms as the 2023 Notes and evidencing the same indebtedness as the 2023 Notes. On December 11, 2015, the Company filed an exchange offer registration statement for the 2023 Notes with the SEC, which was declared effective on January 28, 2016. The exchange offer was completed on March 7, 2016, thereby fulfilling all of the requirements of the 2023 Notes registration rights agreement.

18
Table of Contents

6.50% Senior Notes (the “2021 Notes”)
On March 31, 2014, the Company issued and sold $900.0 million in aggregate principal amount of 6.50% Senior Notes due April 15, 2021, in a private placement pursuant to Section 4(a)(2) of the Securities Act, to eligible purchasers at par. The Company received net proceeds of approximately $884.0 million net of initial purchasers’ fees and expenses, which the Company used to fund the purchase price of ADF Holdings, Inc., the parent company of Anchor Drilling Fluids USA, Inc. (subsequently converted to ADF Holdings, LLC and Anchor Drilling Fluids USA, LLC), the redemption of $500.0 million in aggregate principal amount outstanding of 9.375% Senior Notes due 2019 (the “2019 Notes”) and for general partnership purposes, including planned capital expenditures at the Company’s facilities. Interest on the 2021 Notes is paid semiannually in arrears on April 15 and October 15 of each year, beginning on October 15, 2014.
7.625% Senior Notes (the “2022 Notes”)
On November 26, 2013, the Company issued and sold $350.0 million in aggregate principal amount of 7.625% Senior Notes due January 15, 2022, in a private placement pursuant to Section 4(a)(2) of the Securities Act, to eligible purchasers at a discounted price of 98.494 percent of par. The Company received net proceeds of approximately $337.4 million, net of discount, initial purchasers’ fees and expenses, which the Company used for general partnership purposes, to fund previously announced organic growth projects, the purchase price of the Bel-Ray acquisition and the redemption of $100.0 million in aggregate principal amount outstanding of 9.375% Senior Notes due 2019. Interest on the 2022 Notes is paid semiannually in arrears on January 15 and July 15 of each year, beginning on July 15, 2014.
2021 Secured Notes, 2021 Notes, 2022 Notes and 2023 Notes
In accordance with SEC Rule 3-10 of Regulation S-X, condensed consolidated financial statements of non-guarantors are not required. The Company has no assets or operations independent of its subsidiaries. Obligations under its 2021, 2022 and 2023 Notes are fully and unconditionally and jointly and severally guaranteed on a senior unsecured basis by the Company’s current 100%-owned operating subsidiaries and certain of the Company’s future operating subsidiaries, with the exception of the Company’s “minor” subsidiaries (as defined by Rule 3-10 of Regulation S-X), including Calumet Finance Corp. (100%-owned Delaware corporation that was organized for the sole purpose of being a co-issuer of certain of the Company’s indebtedness, including the 2021 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, 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, 2016, the Company’s Fixed Charge Coverage Ratio (as defined in the indentures governing the 2021 Secured, 2021, 2022 and 2023 Notes) was 0.8 to 1.0. As of June 30, 2016, 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 $1.0 billion senior secured revolving credit facility, subject to borrowing base limitations, which includes a $500.0 million incremental uncommitted expansion feature. The revolving credit facility is the Company’s primary source of liquidity for cash needs in excess of cash generated from operations. The revolving credit facility matures in July 2019 and currently bears interest at a rate equal to either the prime rate plus a basis points margin or the London Interbank Offered Rate (“LIBOR”) plus a basis points margin, at the Company’s option. As of June 30, 2016, the margin was 75 basis points for prime rate loans and

19
Table of Contents

175 basis points for LIBOR rate loans; however, the margin can fluctuate quarterly based on the Company’s average availability for additional borrowings under the revolving credit facility during the preceding fiscal quarter.
In addition to paying interest quarterly on outstanding borrowings under the revolving credit facility, the Company is required to pay a commitment fee to the lenders under the revolving credit facility with respect to the unutilized commitments thereunder at a rate equal to 0.250% or 0.375% per annum, depending on the average daily available unused borrowing capacity for the preceding month. The Company also pays a customary letter of credit fee, including a fronting fee of 0.125% per annum of the stated amount of each outstanding letter of credit, and customary agency fees.
The borrowing capacity as of June 30, 2016, under the revolving credit facility was $502.0 million. As of June 30, 2016, the Company had $0.1 million in outstanding borrowings under the revolving credit facility and outstanding standby letters of credit of $64.4 million, leaving $437.5 million available for additional borrowings based on specified availability limitations. Lenders under the revolving credit facility have a first priority lien on the Company’s accounts receivable, inventory and substantially all of its cash (collectively, the “Credit Agreement Collateral”).
On April 20, 2016, the Company and certain of its operating subsidiaries as borrowers (collectively, the “Borrowers”) entered into a Second Amendment to Second Amended and Restated Credit Agreement (the “Second Amendment”), by and among the Borrowers, the Agent (as defined below) and the lenders party thereto (including Bank of America, N.A.), amending the Company’s revolving credit facility. The Second Amendment, among other things, amends the revolving credit facility to permit (a) the issuance of the 2021 Secured Notes pursuant to the indenture governing the 2021 Secured Notes and (b) such 2021 Secured Notes to be secured by a lien on the Fixed Asset Collateral (as defined in the Intercreditor Agreement), subject to the terms of the Intercreditor Agreement.
The revolving credit facility contains various covenants that limit, among other things, the Company’s ability to: incur indebtedness; grant liens; dispose of certain assets; make certain acquisitions and investments; redeem or prepay other debt or make other restricted payments such as distributions to unitholders; enter into transactions with affiliates and enter into a merger, consolidation or sale of assets. Further, the revolving credit facility contains one springing financial covenant which provides that only if the Company’s availability under the revolving credit facility falls below the greater of (a) 12.5% of the Borrowing Base (as defined in the revolving credit agreement) then in effect and (b) $45.0 million (which amount is subject to increase in proportion to revolving commitment increases), then the Company will be required to maintain as of the end of each fiscal quarter a Fixed Charge Coverage Ratio (as defined in the revolving credit agreement) of at least 1.0 to 1.0.
As of June 30, 2016, the Company was in compliance with all covenants under the revolving credit facility.
Collateral Trust Agreement
In connection with the private placement of the 2021 Secured Notes, on April 20, 2016, the Company entered into a collateral trust agreement (the “Collateral Trust Agreement”) which governs how the holders of the 2021 Secured Notes and secured hedging counterparties share collateral pledged as security for the payment obligations owed by it to the holders of the 2021 Secured Notes and secured hedging counterparties under their respective master derivatives contracts. The Collateral Trust Agreement limits to $150.0 million the extent to which forward purchase contracts for physical commodities are covered by, and secured under, the Collateral Trust Agreement and the Parity Lien Security Documents (as defined in the Collateral Trust Agreement). There is no such limit on financially settled derivative instruments used for commodity hedging. Subject to certain conditions set forth in the Collateral Trust Agreement, the Company has the ability to add secured hedging counterparties from time to time.
Intercreditor Agreement
The 2021 Secured Notes are not secured by the collateral securing the Company’s revolving credit facility. In connection with the offering of the 2021 Secured Notes, the Collateral Trustee entered into a Second Amended and Restated Intercreditor Agreement (the “Intercreditor Agreement”) among the Collateral Trustee, as fixed asset collateral trustee, Bank of America, N.A., as agent for the lenders under the Company’s revolving credit facility (in such capacity, the “Agent”), the Company and the other grantors named therein, providing for certain access and administrative agreements with respect to the Credit Agreement Collateral and the Fixed Asset Collateral (as defined in the Intercreditor Agreement).

20
Table of Contents

Maturities of Long-Term Debt
As of June 30, 2016, principal payments on debt obligations and future minimum rentals on capital lease obligations are as follows (in millions):
Year
 
Maturity
2016
 
$
41.5

2017
 
1.6

2018
 
1.5

2019
 
1.4

2020
 
0.9

Thereafter
 
2,014.5

Total
 
$
2,061.4

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 (“Brent”).
The Company manages its exposure to commodity markets, credit, volumetric and liquidity risks to manage its costs and volatility of cash flows as conditions warrant or opportunities become available. These risks may be managed in a variety of ways that may include the use of derivative instruments. Derivative instruments may be used for the purpose of mitigating risks associated with an asset, liability and anticipated future transactions and the changes in fair value of the Company’s derivative instruments will affect its earnings and cash flows; however, such changes should be offset by price or rate changes related to the underlying commodity or financial transaction that is part of the risk management strategy. The Company does not speculate with derivative instruments or other contractual arrangements that are not associated with its business objectives. Speculation is defined as increasing the Company’s natural position above the maximum position of its physical assets or trading in commodities, currencies or other risk bearing assets that are not associated with the Company’s business activities and objectives. The Company’s positions are monitored routinely by a risk management committee to ensure compliance with its stated risk management policy and documented risk management strategies. All strategies are reviewed on an ongoing basis by the Company’s risk management committee, which will add, remove or revise strategies in anticipation of changes in market conditions and/or in risk profiles. Such changes in strategies are to position the Company in relation to its risk exposures in an attempt to capture market opportunities as they arise. 
The Company recognizes all derivative instruments at their fair values (see Note 9) as either current assets or current liabilities in the condensed consolidated balance sheets. Fair value includes any premiums paid or received and unrealized gains and losses. Fair value does not include any amounts receivable from or payable to counterparties, or collateral provided to counterparties. Derivative asset and liability amounts with the same counterparty are netted against each other for financial reporting purposes. The Company’s financial results are subject to the possibility that changes in a derivative’s fair value could result in significant ineffectiveness and potentially no longer qualify portions or all of its derivative instruments for hedge accounting.

21
Table of Contents

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, 2016, and December 31, 2015 (in millions):
 
 
June 30, 2016
 
December 31, 2015
 
 
Gross Amounts of Recognized Assets
 
Gross Amounts Offset in the Condensed Consolidated Balance Sheets
 
Net Amounts of Assets Presented in the Condensed Consolidated Balance Sheets
 
Gross Amounts of Recognized Assets
 
Gross Amounts Offset in the Condensed Consolidated Balance Sheets
 
Net Amounts of Assets Presented in the Condensed Consolidated Balance Sheets
Derivative instruments not designated as hedges:
 
 
 
 
 
 
 
 
 
 
Specialty products segment:
 
 
 
 
 
 
 
 
 
 
 
 
Natural gas swaps
 
$
—

 
$
(2.6
)
 
$
(2.6
)
 
$
—

 
$
—

 
$
—

Fuel products segment:
 
 
 
 
 


 
 
 
 
 
 
Crude oil swaps
 
14.9

 
(1.6
)
 
13.3

 
—

 
—

 
—

Crude oil basis swaps
 
0.5

 
(5.9
)
 
(5.4
)
 
0.4

 
(0.4
)
 
—

Crude oil percentage basis swaps
 
0.7

 
(0.8
)
 
(0.1
)
 
0.2

 
(0.2
)
 
—

Crude oil options
 
1.0

 
(1.1
)
 
(0.1
)
 
0.8

 
(0.8
)
 
—

Natural gas swaps
 
0.2

 
(0.4
)
 
(0.2
)
 
—

 
—

 
—

Total derivative instruments not designated as hedges
 
17.3

 
(12.4
)
 
4.9

 
1.4

 
(1.4
)
 
—

Total derivative instruments
 
$
17.3


$
(12.4
)

$
4.9


$
1.4


$
(1.4
)

$
—

The following tables summarize the Company’s gross fair values of its derivative instruments, presenting the impact of offsetting derivative liabilities in the Company’s condensed consolidated balance sheets as of June 30, 2016, and December 31, 2015 (in millions):
 
 
June 30, 2016
 
December 31, 2015
 
 
Gross Amounts of Recognized Liabilities
 
Gross Amounts Offset in the Condensed Consolidated Balance Sheets
 
Net Amounts of Liabilities Presented in the Condensed Consolidated Balance Sheets
 
Gross Amounts of Recognized Liabilities
 
Gross Amounts Offset in the Condensed Consolidated Balance Sheets
 
Net Amounts of Liabilities Presented in the Condensed Consolidated Balance Sheets
Derivative instruments not designated as hedges:
 
 
 
 
 
 
 
 
 
 
Specialty products segment:
 
 
 
 
 
 
 
 
 
 
 
 
Natural gas swaps
 
$
(6.4
)
 
$
2.6

 
$
(3.8
)
 
$
(14.9
)
 
$
—

 
$
(14.9
)
Natural gas collars
 
(0.2
)
 
—

 
(0.2
)
 
(0.9
)
 
—

 
(0.9
)
Fuel products segment:
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil swaps
 
(7.1
)
 
1.6

 
(5.5
)
 
(5.2
)
 
—

 
(5.2
)
Crude oil basis swaps
 
(5.7
)
 
5.9

 
0.2

 
(0.7
)
 
0.4

 
(0.3
)
Crude oil percentage basis swaps
 
(2.0
)
 
0.8

 
(1.2
)
 
(6.9
)
 
0.2

 
(6.7
)
Crude oil options
 
(1.1
)
 
1.1

 
—

 
(1.1
)
 
0.8

 
(0.3
)
Gasoline crack spread swaps
 
—

 
—

 
—

 
(4.3
)
 
—

 
(4.3
)
Natural gas swaps
 
(0.3
)
 
0.4

 
0.1

 
(1.3
)
 
—

 
(1.3
)
Total derivative instruments not designated as hedges
(22.8
)
 
12.4

 
(10.4
)
 
(35.3
)
 
1.4

 
(33.9
)
Total derivative instruments
$
(22.8
)

$
12.4


$
(10.4
)

$
(35.3
)

$
1.4


$
(33.9
)
The Company is exposed to credit risk in the event of nonperformance by its counterparties on these derivative transactions. The Company does not expect nonperformance on any derivative instruments, however, no assurances can be provided. The Company’s credit exposure related to these derivative instruments is represented by the fair value of contracts reported as derivative assets. As of June 30, 2016, the Company had three counterparties in which the derivatives held were net assets, totaling $4.9 million. As of December 31, 2015, the Company had no counterparties in which the derivatives held were net assets. To manage credit risk, the Company selects and periodically reviews counterparties based on credit ratings. The Company primarily executes its derivative instruments with large financial institutions that have ratings of at least Baa1 and BBB+ by Moody’s and S&P, respectively. In the event of default, the Company would potentially be subject to losses on derivative instruments with mark-to-

22
Table of Contents

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, 2016, or December 31, 2015. The Company’s contracts with these counterparties allow for netting of derivative instruments executed under each contract. Collateral received from counterparties is reported in other current liabilities, and collateral held by counterparties is reported in deposits on the Company’s condensed consolidated balance sheets and is not netted against derivative assets or liabilities. As of June 30, 2016, and December 31, 2015, the Company had provided its counterparties with no collateral. For financial reporting purposes, the Company does not offset the collateral provided to a counterparty against the fair value of its obligation to that counterparty. Any outstanding collateral is released to the Company upon settlement of the related derivative instrument liability.
Certain of the Company’s outstanding derivative instruments are subject to credit support agreements with the applicable counterparties which contain provisions setting certain credit thresholds above which the Company may be required to post agreed-upon collateral, such as cash or letters of credit, with the counterparty to the extent that the Company’s mark-to-market net liability, if any, on all outstanding derivatives exceeds the credit threshold amount per such credit support agreement. The majority of the credit support agreements covering the Company’s outstanding derivative instruments also contain a general provision stating that if the Company experiences a material adverse change in its business, in the reasonable discretion of the counterparty, the Company’s credit threshold could be lowered by such counterparty. The Company does not expect that it will experience a material adverse change in its business.
The cash flow impact of the Company’s derivative activities is classified primarily as a change in derivative activity in the operating activities section in the unaudited condensed consolidated statements of cash flows.
Derivative Instruments Designated as Cash Flow Hedges
The Company accounts for certain derivatives hedging purchases of crude oil and sales of gasoline, diesel and jet fuel swaps as cash flow hedges. The derivative instruments designated as cash flow hedges that are hedging sales and purchases are recorded to sales and cost of sales, respectively, in the unaudited condensed consolidated statements of operations upon recording the related hedged transaction in sales or cost of sales. The Company assesses, both at inception of the cash flow hedge and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items. Periodically, the Company may enter into crude oil and fuel product basis swaps to more effectively hedge its crude oil purchases, crude oil sales and fuel products sales. These derivatives can be combined with a swap contract in order to create a more effective cash flow hedge. 
To the extent a derivative instrument designated as a cash flow hedge is determined to be effective as a cash flow hedge of an exposure to changes in the fair value of a future transaction, the change in fair value of the derivative is deferred in accumulated other comprehensive income (loss), a component of partners’ capital in the condensed consolidated balance sheets, until the underlying transaction hedged is recognized in the unaudited condensed consolidated statements of operations.
Ineffectiveness is inherent in the hedging of crude oil and fuel products. Due to the volatility in the markets for crude oil and fuel products, the Company is unable to predict the amount of ineffectiveness each period, determined on a derivative by derivative basis or in the aggregate for a specific commodity, and has the potential for the future loss of cash flow hedge accounting. Ineffectiveness has resulted, and the loss of cash flow hedge accounting has resulted, in increased volatility in the Company’s financial results. However, even though certain derivative instruments may not qualify for cash flow hedge accounting, the Company intends to continue to utilize such instruments as management believes such derivative instruments continue to provide the Company with the opportunity to more effectively stabilize cash flows.
Cash flow hedge accounting is discontinued when it is determined that a derivative no longer qualifies as an effective hedge or when it is no longer probable that the hedged forecasted transaction will occur. When cash flow hedge accounting is discontinued because the derivative instrument no longer qualifies as an effective cash flow hedge, the derivative instrument is subject to the mark-to-market method of accounting prospectively. Changes in the mark-to-market fair value of the derivative instrument are recorded to unrealized gain (loss) on derivative instruments in the unaudited condensed consolidated statements of operations. Unrealized gains and losses related to discontinued cash flow hedges that were previously deferred in accumulated other comprehensive income (loss) will remain in accumulated other comprehensive income (loss) until the underlying transaction is reflected in earnings, unless it is probable that the hedged forecasted transaction will not occur, at which time, associated deferred amounts in accumulated other comprehensive income (loss) are immediately recognized in unrealized gain (loss) on derivative instruments in the unaudited condensed consolidated statements of operations.

23
Table of Contents

The Company recorded the following amounts in its condensed consolidated balance sheets, unaudited condensed consolidated statements of operations, unaudited condensed consolidated statements of comprehensive income (loss) and unaudited condensed consolidated statements of partners’ capital as of and for the three months ended June 30, 2016 and 2015, related to its derivative instruments that were designated as cash flow hedges (in millions):
Type of Derivative
Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Loss on Derivatives (Effective Portion)
 
Amount of Gain (Loss) Reclassified from Accumulated Other Comprehensive Loss into Net Income (Loss) (Effective Portion)
 
Amount of Gain (Loss) Recognized in Net Income (Loss) on Derivatives (Ineffective Portion)
Three Months Ended
 
Location of Gain (Loss)
 
Three Months Ended
 
Location of Gain (Loss)
 
Three Months Ended
June 30,
 
 
June 30,
 
 
June 30,
2016
 
2015
 
 
2016
 
2015
 
 
2016
 
2015
Specialty products segment:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil swaps
$
—

 
$
—

 
Cost of sales
 
$
(0.5
)
 
$
1.6

 
Unrealized/ Realized
 
$
—

 
$
—

Fuel products segment:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil swaps
(4.5
)
 
(2.7
)
 
Cost of sales
 
(12.3
)
 
(53.2
)
 
Unrealized/ Realized
 
—

 
—

Gasoline swaps
—

 
2.7

 
Sales
 
—

 
19.3

 
Unrealized/ Realized
 
—

 
—

Diesel swaps
4.5

 
(1.4
)
 
Sales
 
15.1

 
39.8

 
Unrealized/ Realized
 
—

 
—

Jet fuel swaps
—

 
0.3

 
Sales
 
—

 
4.0

 
Unrealized/ Realized
 
—

 
—

Total
$
—

 
$
(1.1
)
 
 
 
$
2.3

 
$
11.5

 
 
 
$
—

 
$
—

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, 2016 and 2015, related to its derivative instruments that were designated as cash flow hedges (in millions):
Type of Derivative
Amount of Gain (Loss) Recognized in Accumulated Other Comprehensive Loss on Derivatives (Effective Portion)
 
Amount of Gain (Loss) Reclassified from Accumulated Other Comprehensive Loss into Net Income (Loss) (Effective Portion)
 
Amount of Gain (Loss) Recognized in Net Income (Loss) on Derivatives (Ineffective Portion)
Six Months Ended
 
Location of Gain (Loss)
 
Six Months Ended
 
Location of Gain (Loss)
 
Six Months Ended
June 30,
 
 
June 30,
 
 
June 30,
2016
 
2015
 
 
2016
 
2015
 
 
2016
 
2015
Specialty products segment:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil swaps
$
—

 
$
—

 
Cost of sales
 
$
(1.2
)
 
$
1.2

 
Unrealized/ Realized
 
$
—

 
$
—

Fuel products segment:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil swaps
(5.8
)
 
(9.0
)
 
Cost of sales
 
(25.5
)
 
(74.7
)
 
Unrealized/ Realized
 
—

 
(0.2
)
Gasoline swaps
—

 
3.5

 
Sales
 
—

 
33.3

 
Unrealized/ Realized
 
—

 
0.7

Diesel swaps
5.8

 
(1.3
)
 
Sales
 
31.1

 
44.6

 
Unrealized/ Realized
 
—

 
—

Jet fuel swaps
—

 
0.6

 
Sales
 
—

 
5.4

 
Unrealized/ Realized
 
—

 
—

Total
$
—

 
$
(6.2
)
 
 
 
$
4.4

 
$
9.8

 
 
 
$
—

 
$
0.5

The effective portion of the cash flow hedges classified in accumulated other comprehensive loss was gains of $2.0 million and $6.4 million as of June 30, 2016, and December 31, 2015, respectively. Absent a change in the fair market value of the underlying transactions, except for any underlying transactions pertaining to the payment of interest on existing financial instruments, the following other comprehensive income at June 30, 2016, will be reclassified to earnings by December 31, 2016, with balances being recognized as follows (in millions):
Year
Accumulated Other Comprehensive Income
2016
$
2.0

Total
$
2.0


24
Table of Contents

Derivative Instruments Designated as Fair Value Hedges
For derivative instruments that are designated and qualify as a fair value hedge (which are limited to interest rate swaps), the effective gain or loss on the derivative instrument, as well as the offsetting gain or loss on the hedged item attributable to the hedged risk are recognized as interest expense in the unaudited condensed consolidated statements of operations. No hedge ineffectiveness is recognized if the interest rate swap qualifies for the “shortcut” method and, as a result, changes in the fair value of the derivative instrument offset the changes in the fair value of the underlying hedged debt. In addition, the differential to be paid or received on the interest rate swap arrangement is accrued and recognized as an adjustment to interest expense in the unaudited condensed consolidated statements of operations. The Company assesses at the inception of the fair value hedge whether the derivatives that are used in the hedging transactions are highly effective in offsetting changes in fair values of hedged items.
Fair value hedge accounting is discontinued when it is determined that a derivative no longer qualifies as an effective hedge or when it is no longer probable that the hedged forecasted transaction will occur. When fair value hedge accounting is discontinued because the derivative instrument no longer qualifies as 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 gains (losses) in its unaudited condensed consolidated statements of operations for the three and six months ended June 30, 2016 and 2015, related to its derivative instrument designated as a fair value hedge (in millions):

Location of Loss of Derivative

Amount of Loss Recognized in Net Income (Loss)

Hedged Item
 
Location of Gain on Hedged Item

Amount of Gain Recognized in Net Income (Loss)

Three Months Ended June 30,

Six Months Ended June 30,


Three Months Ended June 30,

Six Months Ended June 30,

2016
 
2015

2016
 
2015


2016
 
2015

2016
 
2015
Swaps not allocated to a specific segment:
 



 



 
 


 
 
Interest rate swap
Interest expense

$
0.1

 
$
0.1


$
0.2

 
$
0.3


2022 Notes
 
Interest income

$
—

 
$
—


$
—

 
$
—

Total


$
0.1

 
$
0.1


$
0.2

 
$
0.3



 


$
—

 
$
—


$
—

 
$
—

Derivative Instruments Not Designated as Hedges
For derivative instruments not designated as hedges, the change in fair value of the asset or liability for the period is recorded to unrealized gain (loss) on derivative instruments in the unaudited condensed consolidated statements of operations. Upon the settlement of a derivative not designated as a hedge, the gain or loss at settlement is recorded to realized gain (loss) on derivative instruments in the unaudited condensed consolidated statements of operations. The Company has entered into crude oil basis swaps that do not qualify as cash flow hedges for accounting purposes as they were not entered into simultaneously with a corresponding NYMEX WTI derivative contract. Additionally, the Company has entered into natural gas collars, 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 gasoline and diesel sales at the Company’s refineries.
The amount reclassified from accumulated other comprehensive loss into earnings, as a result of the discontinuance of cash flow hedge accounting for certain crude oil, gasoline, jet fuel and diesel derivative instruments at the Shreveport refinery because it was no longer probable that the original forecasted transaction would occur by the end of the originally specified time period, caused the Company to recognize the following gains in the unaudited condensed consolidated statements of operations for the six months ended June 30, 2016 and 2015 (in millions):
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2016
 
2015
 
2016
 
2015
Realized gain (loss) on derivative instruments
$
—

 
$
1.2

 
$
—

 
$
2.4


25
Table of Contents

The Company recorded the following gains (losses) in its unaudited condensed consolidated statements of operations for the three months ended June 30, 2016 and 2015, related to its derivative instruments not designated as hedges (in millions):
Type of Derivative
Amount of Gain (Loss) Recognized in Realized Loss on Derivative Instruments
 
Amount of Gain (Loss) Recognized in Unrealized Gain on Derivative Instruments
Three Months Ended June 30,
 
Three Months Ended June 30,
2016
 
2015
 
2016
 
2015
Specialty products segment:
 
 
 
 
 
 
 
Natural gas swaps
$
(3.2
)
 
$
(2.5
)
 
$
6.6

 
$
3.1

Natural gas collars
(0.4
)
 
—

 
0.5

 
—

Platinum swaps
—

 
—

 
—

 
(0.2
)
Fuel products segment:
 
 
 
 
 
 
 
Crude oil swaps
0.1

 
7.7

 
11.5

 
5.2

Crude oil basis swaps
0.1

 
—

 
(2.3
)
 
2.2

Crude oil percentage basis swaps
(0.5
)
 
—

 
5.2

 
—

Crude oil options
(1.5
)
 
—

 
0.8

 
—

Gasoline swaps
—

 
(16.5
)
 
—

 
(7.0
)
Gasoline crack spread swaps
—

 
(3.9
)
 
—

 
(1.7
)
Diesel swaps
—

 
1.2

 
—

 
(3.8
)
Diesel crack spread swaps
—

 
—

 
—

 
7.4

Natural gas swaps
(0.6
)
 
—

 
1.5

 
—

Total
$
(6.0
)
 
$
(14.0
)
 
$
23.8

 
$
5.2

The Company recorded the following gains (losses) in its unaudited condensed consolidated statements of operations for the six months ended June 30, 2016 and 2015, related to its derivative instruments not designated as hedges (in millions):
Type of Derivative
Amount of Gain (Loss) Recognized in Realized Loss on Derivative Instruments
 
Amount of Gain (Loss) Recognized in Unrealized Gain (Loss) on Derivative Instruments
Six Months Ended June 30,
 
Six Months Ended June 30,
2016
 
2015
 
2016
 
2015
Specialty products segment:
 
 
 
 
 
 
 
Natural gas swaps
$
(6.6
)
 
$
(4.6
)
 
$
8.5

 
$
(0.1
)
Natural gas collars
(0.7
)
 
—

 
0.6

 
—

Platinum swaps
—

 
—

 
—

 
(0.3
)
Fuel products segment:
 
 
 
 
 
 
 
Crude oil swaps
(0.8
)
 
(40.6
)
 
13.0

 
55.4

Crude oil basis swaps
0.1

 
1.0

 
(4.9
)
 
1.8

Crude oil percentage basis swaps
(4.4
)
 
—

 
5.4

 
—

Crude oil options
(1.5
)
 
—

 
0.2

 
—

Crude oil futures
(2.0
)
 
—

 
—

 
—

Gasoline swaps
—

 
(18.4
)
 
—

 
(8.2
)
Gasoline crack spread swaps
(1.2
)
 
(4.7
)
 
4.3

 
(3.2
)
Diesel swaps
—

 
59.2

 
—

 
(67.2
)
Diesel crack spread swaps
—

 
0.9

 
—

 
1.0

Jet fuel swaps
—

 
1.6

 
—

 
(1.6
)
Natural gas swaps
(1.2
)
 
—

 
1.3

 
(0.3
)
Total
$
(18.3
)
 
$
(5.6
)
 
$
28.4

 
$
(22.7
)

26
Table of Contents

Derivative Positions — Specialty Products Segment
Natural Gas Swap Contracts
At June 30, 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
Third Quarter 2016
1,380,000


$
4.26

Fourth Quarter 2016
1,540,000


$
4.14

Calendar Year 2017
4,950,000

 
$
3.85

Total
7,870,000



Average price


$
3.98

At December 31, 2015, the Company had the following derivatives related to natural gas purchases in its specialty products segment, none of which are designated as hedges:
Natural Gas Swap Contracts by Expiration Dates
MMBtu

$/MMBtu
First Quarter 2016
1,580,000


$
4.24

Second Quarter 2016
1,380,000


$
4.26

Third Quarter 2016
1,380,000


$
4.26

Fourth Quarter 2016
1,540,000


$
4.14

Calendar Year 2017
4,950,000


$
3.85

Total
10,830,000



Average price


$
4.05

Natural Gas Collars
At June 30, 2016, the Company had the following derivatives related to natural gas purchases in its specialty products segment, none of which are designated as hedges:
Natural Gas Collars by Expiration Dates
MMBtu
 
Average Bought Call ($/MMBtu)
 
Average Sold Put ($/MMBtu)
Third Quarter 2016
180,000

 
$
4.25

 
$
3.89

Fourth Quarter 2016
60,000

 
$
4.25

 
$
3.89

Total
240,000

 
 
 
 
Average price
 
 
$
4.25

 
$
3.89

At December 31, 2015, the Company had the following derivatives related to natural gas purchases in its specialty products segment, none of which are designated as hedges:
Natural Gas Collars by Expiration Dates
MMBtu
 
Average Bought Call ($/MMBtu)
 
Average Sold Put ($/MMBtu)
First Quarter 2016
180,000

 
$
4.25

 
$
3.89

Second Quarter 2016
180,000

 
$
4.25

 
$
3.89

Third Quarter 2016
180,000

 
$
4.25

 
$
3.89

Fourth Quarter 2016
60,000

 
$
4.25

 
$
3.89

Total
600,000

 
 
 
 
Average price
 
 
$
4.25

 
$
3.89


27
Table of Contents

Derivative Positions — Fuel Products Segment
Crude Oil Swap Contracts
At June 30, 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)
Third Quarter 2016
398,894

 
4,336

 
$
39.46

Fourth Quarter 2016
398,894

 
4,336

 
$
39.46

Calendar Year 2017
1,297,977

 
3,556

 
$
48.87

Total
2,095,765


 
 
 
Average price
 
 
 

$
45.29

At June 30, 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)
Calendar Year 2017
528,520

 
1,448

 
$
41.56

Total
528,520

 
 
 
 
Average price
 
 
 
 
$
41.56

At December 31, 2015, the Company had the following derivatives related to crude oil purchases in its fuel products segment, none of which are designated as hedges:
Crude Oil Swap Contracts by Expiration Dates
Barrels Purchased
 
BPD
 
Average Swap
($/Bbl)
First Quarter 2016
29,120

 
320

 
$
44.06

Second Quarter 2016
29,120

 
320

 
$
44.06

Third Quarter 2016
29,440

 
320

 
$
44.06

Fourth Quarter 2016
29,440

 
320

 
$
44.06

Calendar Year 2017
630,720

 
1,728

 
$
54.94

Total
747,840

 
 
 
 
Average price
 
 
 
 
$
53.24

Crude Oil Basis Swap Contracts
The Company has entered into crude oil basis swaps to mitigate the risk of future changes in pricing differentials between LLS and NYMEX WTI. At June 30, 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)
Third Quarter 2016
460,000

 
5,000

 
$
1.80

Fourth Quarter 2016
460,000

 
5,000

 
$
1.80

Total
920,000

 
 
 
 
Average differential
 
 
 
 
$
1.80


28
Table of Contents

At December 31, 2015, the Company had the following derivatives related to crude oil basis swaps in its fuel products segment, none of which are designated as hedges:
Crude Oil Basis Swap Contracts by Expiration Dates
Barrels Purchased